Commenter 9665 used the capacity factor limits from 35 recent simple cycle permits as the basis for objecting to the EPA's use of an historical analysis to estimate that "approximately one percent" of new simple cycle turbines will be affected by the proposed rule based on the one-third sales criterion. Commenter 10095 identified 19 simple cycle units with annual capacity factor permit limits ranging from approximately 40 percent to 55 percent. Commenters (9665, 10095, 10098) do not believe that the EPA's historical analysis of simple cycle capacity factors provides the substantial evidence that is required to support the proposed standards. Commenter 8952 also provided data showing the current unprecedented rate of retirements of steam plants. Commenters (8952, 10098) believed that this accelerated rate of retirement could drive system operators to select the faster construction schedules associated with simple cycle turbines to maintain grid reliability until more cost-effective combined cycle units can be constructed. Commenters (8952, 9665) pointed out that regional grid operators compensate generating facilities not only on the amount of energy that they actually deliver to the grid, but they also compensate generators based on the amount of capacity the generator has readily available to the dispatcher to respond to emergent conditions. These commenters indicated that the one-third sales criterion will decrease the reserve capacity that can be bought and sold in these capacity markets; they believed this criterion is burdensome and that it highlights the fact that there is no compliance technology available for the end-users of simple cycle technologies because the method of control is essentially achieved by limiting the operation of the facility. Commenter 9665 believed that within capacity markets, the proposed capacity factor limit on simple cycle gas turbines will act as an incentive to install modularized sets of reciprocating engines (which are subject to no capacity factor limitations under the NSPS), resulting in significant financial impact to owners of simple cycle units participating in those capacity markets.
The EPA notes that the applicability criterion in question is based on the percentage of electric sales relative to potential electric output, not capacity factor. The EPA conducted extensive analysis on the historical percentage of electric sales for simple cycle turbines and has concluded that the sliding-scale approach provides sufficient flexibility for the continued use of simple cycle turbines.
 Commenter (9427) asked why applicability criteria were proposed on a net megawatt hour basis while the emissions standards were proposed on a gross megawatt hour basis. This commenter recommended that applicability should be based on potential electric output (megawatt hours) of the combustion turbine and the actual gross electrical output of the combustion turbine. The commenter also recommended that the EPA revise the definition of "potential electric output" in section 60.4221 to use the design electric output efficiency of the combustion turbine on a gross output (megawatt hour) basis.
The applicability and subcategorization criteria are based on net output because that is the defining factor that determines whether a unit is an EGU. However, for the reasons discussed in Section III.F of this final rule, the primary standards in this final rule are on a gross-output basis.
Commenter 10681 would insert an enforceable condition into an NSR permit to assure a unit remains exempt from the requirements of the NSPS.
 Commenter 5537 stated to avoid NSPS, the EGU must be subject to an enforceable operational limit in its operating permit so that from its initial construction, it is not allowed to exceed any of the threshold criteria listed by the EPA at any point in its operating lifetime that would have made it subject to NSPS at the time of construction.
Commenters (5537, 9771) believed that in order for a source to avoid applicability of the NSPS, the source must be subject to a federally enforceable permit limit with associated monitoring, recordkeeping, and reporting conditions for assessing applicability on an ongoing basis as required by many federally approved SIPs.
Commenter 10681, a pre-construction permitting authority, responded to the EPA's request for input on implementation of the proposed 3 year average sales criterion and stated that the 3 year average criterion would become a continuing compliance obligation of the source because a one-time, preconstruction demonstration based on design considerations would not assure that operations would not change in the future. Commenter 10681 stated they would insert an enforceable condition into an NSR permit to assure potentially affected units remain exempt from applicable requirements.
 Commenter 9427 was confused by use of a different averaging period for applicability (3 years) compared to the averaging period used for compliance (12 months). Commenter 9427 asked, does the EPA intend for the operator to wait until the end of first 3-year applicability period is satisfied, and then comply going forward; in Title V annual compliance certifications, how can an operator certify compliance prior to the end of the first 3-year period; how are applicability and compliance determined for a combustion turbine that routinely operates above and below applicability thresholds over consecutive but overlapping 3-year.
 Commenter 9666 stated that without factoring in the impact of the one third sales criterion in the compliance analysis, it is not possible to determine achievability of the proposed standards, and the commenter found that the methodology for implementing the one-third sales criterion is undefined in the proposal. Commenter 9666 found that the inconsistency between the three year averaging period proposed for the one-third sales criterion compared to the 12-month period proposed for the CO2 limit caused serious ambiguity in trying to evaluate how the one-third sales criterion might affect compliance rates (by exempting some units). Commenter 9666 posed several questions related to implementation of the one-third sales criterion and reconciliation of the 3-year average exemption criteria (20 to 40%) with the 12-month compliance average to evaluate achievability:  (1) If a turbine operates less than the 3 year average sales criterion, how long does the exemption last? (2) If a turbine is exempt during a three-year period, does the exemption continue for an additional 3 years; does the exemption continue through the end of the next year; does the exemption continue until the end of the next rolling month compliance determination? (3) What compliance determination would the EPA make during the first three years if a 12-month violation of the CO2 limit occurs?
 Commenter 9666 stated that uncertainty on the preceding implementation issues made it difficult to comment on both the associated range of sales criterion suggested by the EPA and achievability across the range of CO2 limits included in the proposal.
 Commenter 10095 posed a series of questions asking for clarification of applicability criteria. Commenter 10095 recommended several changes to the proposal's applicability criteria for NGCCs and simple-cycle CTs. If EPA retains the current applicability criteria as proposed, clarification is needed to address a range of compliance uncertainties. The commenter reviewed EPA's proposed applicability criteria for CTs, and the commenter recommended EPA must clarify how these three applicability criteria interact with the proposed 12-operating month rolling average compliance requirement. For example, if a CT does not meet the 90 percent natural gas criteria, from which 12-operating month rolling average compliance determinations are the affected facility excluded?
 Commenter 2470 stated that they support the addition of the three-year rolling average methodology for determining the applicability of the proposed rule for simple cycle combustion turbines.
 Commenters (3862, 9425, 9666, 9770, 9777, 10023, 10619) supported the proposed revision of the averaging period for electric sales by combustion turbines from an annual basis to a three-year rolling average basis, and stated that applicability based on the actual capacity factor during the preceding compliance period would provide some regulatory clarity for simple cycle units that may be periodically dispatched at high capacity factors. Commenters (9425, 9666, 10095) also requested that the EPA clarify how the three-year rolling average will be implemented, and stated that the final rule should include a full three-year period for the initial compliance determination.
Commenter 10095, a regional electric utility, stated that the proposed one-third sales criteria are confusing and problematic for NGCCs because the applicability criteria are evaluated as a three-year rolling average, but compliance is evaluated on a 12-month basis; the commenter recommended that the EPA should revise the applicability criteria for NGCCs to match the compliance period for NGCCs. This commenter also requested clarifications on how the EPA intends to implement the multiple applicability criteria proposed over differing rolling averaging periods.
 Commenter 10095 stated that EPA's applicability criteria are confusing and problematic for NGCCs, specifically, the rolling three-year one-third sales criteria. Because the compliance period is proposed to be on a 12-month basis while the applicability criteria is a three-year basis, The commenter stated that EPA appears to have inadvertently created issues for NGCCs. As proposed, NGCCs with single-year sales below one-third of its potential output (or a 33 percent capacity factor) could be subject, in that year, to the proposed standard if the surrounding years' sales (or capacity factors) were high enough to create a three-year average over 33 percent. For example, assume an NGCC operates for three consecutive years with capacity factors at 50, 60, and 20 percent, respectively. Absent these alterations, the commenter felt that the proposed standard affecting NGCCs is too stringent and unnecessarily restricts operating flexibility.
 Commenter 8952 stated that the 3 year averaging period is unfortunately of limited benefit. The commenter stated that capacity is forward looking. The commenter stated that an individual year of high energy demand, for unforeseen demand or supply issues, would decrease the available margin over the next 2 years.
Commenter 9425, 9780 also requested that the EPA clarify whether a simple cycle unit that exceeded the sales criterion for a series of compliance periods would be subject to the standard only during those discrete compliance periods or would the EPA invoke the "once in always in" doctrine for all subsequent 3 year averages.
Commenter 9425 stated that EPA must address whether simple-cycle units that exceed the one-third sales test would be subject to an emissions limit only for those periods in which sales exceeded the limit or, once the test has been failed, would be required to comply for all operating periods going forward, regardless of whether sales later return to levels that would entitle the simple cycle CT to take advantage of the proposed changes to the applicability requirements.
Commenter 5537 stated that NSPS regulations are intended to be "once-in-always-in" provisions, which have always been EPA's policy and practice for other sources, and for other pollutants from similar sources. The commenter believed that NSPS applicability should not be "optional" in that it may disappear and return from year-to-year.
 Rather than delaying the applicability determination until after beginning operations, Commenter 5537 stated that NSPS regulations are intended to be "once-in-always-in" provisions, and opposed proposed applicability provisions that could change applicability determinations from year-to-year.
Commenter 7540 encouraged EPA to ensure that the final rule allows new units this "ramp up" period before the rule applies as it is a more accurate representation of actual lifetime performance than the first few months. In addition, Commenter 7540 stated EPA should clarify that the rule does not apply to units that fall below the three-year rolling average threshold, even if the unit had previously exceeded the threshold (e.g., the standard is not "once in, always in"). Commenter 7540 stated that if a unit's role in the electric system or dispatch profile changes, it should no longer be covered by the rule (unless it again exceeds the threshold) and vice versa. Commenter 7540 noted that as currently drafted, if a unit were to limit its utilization below the sales threshold after initially being subject to the standard, it may continue to be subject to the standard for at least three years as it demonstrates that its three-year sales are below the threshold. Commenter 7540 noted that in this situation, they recommend that EPA allow a unit to accept a permit limitation exempting it from the standard, rather than having to accumulate three years of operating data showing that it no longer meets the applicability provisions.
 Commenter 9678 recommended adding a once-in-not-always-in clarification consistent with the treatment of emergency generators under 40 CFR Part 63 and consistent with the treatment of cement kilns in the recent CISWI rule. Commenter 9678 recommended that units initially above the one-third sales criterion should remain eligible for the exclusion during future compliance periods with capacity factors below the threshold. Commenter 10100 also recommended that the final rule should extend the exclusion to cover other types of units that provide peaking power because in addition to combustion turbines, the commenter stated that other types of new units can also provide peaking service.
Commenter 9666 stated that the methodology of implementing the less than one-third sales criterion is undefined in the proposal. The commenter stated that this causes serious ambiguity because the proposed rule is based on a rolling 12-operating month period and determines compliance with the CO2 limits after the first 12 operating months, while the one-third sales criterion is based on 3-calendar year average sales which would not be calculated until 3 calendar years of operation had passed. Based on the information provided in the proposed rule, the commenter believed that it is not possible to accurately determine which of the turbines that EPA evaluated in Docket Item -0082 might have satisfied the one-third sales criterion and therefore be eliminated from the achievability analysis. The commenter stated that including this one-third criterion in the analysis likely affects the achievability level. The commenter stated the analysis performed by EPA did not filter out the turbines that might have met the one-third sales criterion, nevertheless, it was considered by EPA to be conservative without quantifying the level of conservatism. Without applying this filter to the dataset, the commenter stated it is impossible to determine how conservative EPA's analysis is. The commenter stated that the question is whether, by including this filter, EPA's conclusions on the level of the CO2 limit for compliance would have changed or if the proposed the range of sales criterion (20 to 40 percent) is appropriate. The commenter then posed a series of questions for the EPA:
      1. If a turbine meets the sales criterion, how long does the exemption last?
      a. Only during the 3-year period when the sales criterion was met?
      b. If it is exempt for a given period, what is that period?
            i. That 3-year period only?
            ii. Up until the end of the subsequent 3-year period?
            iii. Up until the next calendar year?
            iv. Up until the next rolling month compliance determination?
      2. What happens to the compliance determination during the first three years if a 12-operating month violation of the CO2 limit occurs?
      a. Is it subject to penalties and possibly be forced to cease operation at that point?
      b. Is it only subject to penalties and possibly be forced to cease operation after the first 3-year period has occurred?
The final applicability criteria are based on operating permit conditions and not on actual operating parameters. This approach will prevent units from moving in and out of applicability. Instead, actual operating parameters (i.e., percentage electric sales and fuel use) will be used to distinguish between three combustion turbine subcategories. See Sections IX.A and B for a more detailed discussion, including related issues, such as averaging periods.
Integrated Equipment
Commenters (9514) supported the additional language defining steam generating unit to include any integrated equipment that provides useful thermal output to the affected facility. Commenters (9514) opposed the additional language defining steam generating unit to include any integrated equipment that provides electricity to the affected facility because the commenters were concerned that the proposed definition would allow electric power supplied by a separate generating source with lower emissions to be used to meet the auxiliary power needs of a coal-fired CCS plant to improve the plant's calculated emission rate; the commenters believed that such an arrangement would constitute circumvention, and the commenter was concerned that the proposed revisions for integrated equipment may encourage some operators to circumvent the GHG performance standards. Accordingly, commenter (9514) recommended that EPA consider language that distinguishes between integral and integrated systems and also recommended that the preamble to the final rule include a discussion that provides guidance as to how it will apply the circumvention provisions under 40 C.F.R. section 60.12; the commenter also expressed concerns about circumvention by IGCC operators that may seek to avoid applicability of the rule by segregating the coal gasification process (i.e., seek to modify their operations to become segregated gasification combined cycle (SGCC) operators), and the commenter provided recommendations to prevent this potential method of circumvention by IGCC operators. Commenter (9514) also recommended that the relevant appendices to the rule should require a source that wishes to construct a configuration not expressly discussed in the rule or preamble to seek an applicability determination or alternate compliance demonstration approval for such systems prior to commencing construction, and the commenter provided a series of potential scenarios to discuss in the preamble of the final rule. Commenters (9514) opposed the addition of language to include "co-located non-emitting energy generation included in the facility operating permit" because the commenter does not believe that this language is consistent with the Congressional intent of section 111 standards: to ensure that new sources are built using cutting-edge technology to minimize emissions.
The definition of affected facility in the final rule includes integrated equipment. This approach does not circumvent the intent of the rule. The emission standard is based on the use of the BSER identified by the EPA. While integrated equipment is not part of the BSER, owners and operators are free to use integrated equipment as an approach to meet the emission standard and reduce site-specific costs.
Commenters (9733, 10038, 10682) generally supported the proposals applicability provisions for CHP plants and establishment of output-based standards.  Commenter 10682 expressed concerns that the definition of CHP in the rule may be too narrow, and unnecessarily limit applicability because some CHP projects produce hot oil, rather than steam. Commenter 10682 recommended the final rule should omit the phrase "steam-generating" from the definition of CHP.
Commenters (8952, 10098) opposed the application of the NSPS standard to CHP projects and recommended that the final rule include a CHP exemption because such an exemption would encourage development of beneficial CHP projects.
Commenter 10098 stated that application of the proposed standard to industrial, commercial and institutional combined heat and power units is arbitrary and capricious, and added that there are a number of ways in which EPA could exclude industrial, commercial, and institutional CHP units from the proposed rule. Commenter 10098 also stated that an exemption for CHP is necessary because industrial, commercial, and institutional CHP units are typically customized to suit the host's needs and that development of standard compliance calculations is impractical for the disparate collection of CHP operations and joint ventures with mixed ownership. Commenter 10098 also stated that the EPA provided no information in the proposal regarding how many CHP units were actually capable of meeting the proposed rule's emission limitations. This commenter disagreed with the hypothetical CHP example provided by the EPA in response to comments from the Office of Management and Budget because the example assumed steady state operations. Commenter 10098 also stated that no real-world data on CHP operations or emissions was included in the proposed rule or in the RIA and requested that the EPA exclude industrial, commercial and institutional CHP units from the rule. Commenter 10098 concluded that it would be arbitrary and capricious for the EPA to apply the standard to industrial, commercial and institutional CHP with no supporting data in the record. Commenter 10098 recommended incorporation of explicit exemptions for CHP units at facilities that are classified as industrial (e.g., gas-fired CHPs within SIC codes 2911, 13XX, and other industrial SIC codes as appropriate).
Commenter 10098 also stated that EPA should include language excluding from applicability new, modified or existing cogeneration units (defined as units that simultaneously produce power and heat and have an energy savings of 10% or more.) Commenter 10098 stated that the final rule should restrict the definition of affected facility to include only industrial-commercial-institutional cogeneration units that supply, on a net basis, more than two-thirds of their potential combined thermal and electric energy output and more than 450,000 MWh net-electric output to a utility power distribution system on an annual basis for 5 consecutive calendar years and that CHP units which have total thermal energy production that approaches or exceeds the unit's total electricity production should be exempted. The commenter went on to describe a number of strategies for incorporating an exemption for CHP units including exempting CHP units by fuel type and exempting industrial CHP units based on the definition of potential electric output, suggesting use of a default efficiency of 50 percent.
While supporting an exemption for cogeneration facilities, commenter 10606 stated that if the EPA is unwilling to grant a blanket exemption for all CHP facilities, then the EPA should grant an exemption for all CHP facilities that will use natural gas as their primary fuel, because such an exemption will provide relief for the commenter and other similar companies that use clean fuel (natural gas), but that cannot readily comply with the proposed standard. The commenter added that restricting the exemption to natural gas will ensure the exemption cannot be used to construct new coal-fired plants.
Commenter 9201 summarized the EPA's longstanding practice of differentiating industrial cogeneration from electricity generated by public utilities, and the commenter encouraged the EPA to continue to differentiate these two types of sources as it moves forward with regulating CO2 emissions by relying on the Acid Rain program's definitions as proposed; the commenter supported the exemptions for cogeneration and related definitions in the proposed rulemaking.
Commenter 10038, a proponent of CHP systems, supported the proposed exclusions of facilities with design heat input of less than 250 MMBtu/hr, facilities that supply less than 219,000 MWh of net electric generation to the utility distribution system, and facilities that supply less than one-third of their potential electric output to the utility distribution system, but the commenter believed the final rule should further tailor the applicability provisions already in the proposed rule to more closely reflect the realities of industrial CHP units by using overall system efficiency when calculating potential electric output. The commenter stated EPA should use overall system efficiency when calculating potential electric output. The commenter noted that the EPA allows facilities to use actual electric efficiency in calculating potential electric output, but also noted that the definition of potential electric output only allows facilities to account for actual "design electric output efficiency." The commenter believed that as written, CHP facilities with very high overall system efficiencies would not meet this definition. The commenter recommended that CHP facilities that supply at least 20% of total output as useful thermal output should be allowed to make this calculation on the basis of overall system efficiency.
Commenter 10038 stated that the EPA should adopt applicability criteria excluding all high-efficiency CHP units so that all CHP systems with efficiencies above 65%-in addition to the other proposed exclusions because this additional criterion would encourage high efficiency generation with only a very remote possibility that it would encourage a high-emitting new generator to add CHP as a means of avoiding applicability of the standard.
Commenter 10038 requested that the final rule clarify design-based vs. operations-based requirements in applicability criteria as related to CHP plants because the commenter believed the proposal was unclear on the interaction between the intended purpose provisions and the operational look-back provisions. The commenter stated that the language of the preamble and the proposed regulation has resulted in some confusion and provided the following examples: if a CHP facility that is designed to supply less than 219,000 MWh net electric output to the grid later signs a contract obligating it to supply more than that amount, will the resulting change in operations cause the facility to be a covered facility? If a CHP facility that is designed to sell a large portion and amount of electricity to the grid is not needed and so actually sells less than 219,000 MWh net electric output or less than one-third potential electric output, would that facility be a covered facility?
Given the environmental benefits of CHP units and the government's affirmative steps to promote increased industrial distributed generation, EPA should exempt industrial, commercial and institutional CHP units entirely from the proposed rule.
Commenter 10682 also expressed concerns that the rule does not clearly apply to waste heat to power projects, and the commenter encouraged EPA to add a separate definition of waste heat to power (WHP) to clarify that incentives that apply to CHP (e.g., the line-loss credit) also extend to WHP and the commenter provided a definition of WHP for consideration by the EPA.
Commenters 0829, 10682 supported the proposed applicability provisions excluding units that sell to third-party developers and believed these provisions will exempt the vast majority of CHP projects from the NSPS because the of the one-third sales criterion included by the EPA and the associated exclusion of power purchases from the definition of "net electric output." The commenter supported the proposed provisions clarifying that applicability will be based on gross electric sales to the utility minus purchased power of the thermal host facility because of the substantial upfront cost and ongoing maintenance responsibilities for a CHP or WHP system.
Commenter 9733 supported the EPA's clarification that a thermal host may be owned by a different legal entity than the owner of the CHP, and that applicability of the standard to the thermal host will not necessarily make the CHP unit subject to the standard.
Commenter 9733 supported the EPA's clarification that a thermal host may be owned by a different legal entity than the owner of the CHP and the associated clarifications on applicability for CHP units.
Commenter 9733 believed that the proposal's applicability criteria appropriately exclude most forest products industry CHP units from coverage. This commenter believed that the final rule should not only continue to exempt those facilities, but should also exempt all CHP units where useful thermal output accounts for at least 20 percent of the total useful output as EPA had considered in its April 2012 proposed rule because this approach recognizes the environmental benefits of CHP and provides additional incentives for CHP construction. This commenter asserted that the inherent efficiency of CHP facilities enables them to operate at emission rates lower than the proposed standard. Commenter 9733 stated that if the EPA does not agree to explicitly exempt all CHP units where useful thermal output accounts for at least 20 percent of total useful output, the commenter recommended that the EPA categorically exempt industrial CHP units because these units are fundamentally different than electric utility units.
Commenter 9194 supported exclusion of combined heat and power (CHP) units that generate greater than 25 MWs with overall efficiencies greater than 70%.
Commenter 9734 stated that EPA should clarify that the addition of a HRSG to an existing CT to convert to more efficient NGCC operation will not be covered by the proposed rule. The commenter stated that if EPA preserves the ability of electricity generators to convert less efficient CTs into highly efficient NGCC units, the goals of the proposed NSPS and reliability will both be served. The commenter felt that it is counterintuitive to restrict such conversions, as the GHG reductions and reduced fossil fuel consumption should be encouraged rather than hindered.
 Commenter (9733) supported exemption of industrial CHP plants because they are significantly different than EGUs. Commenters (9194, 9592) supported explicit exemption of combined heat and power (CHP) units that generate greater than 25 MWs with an overall efficiency greater than 70% because, the commenter asserted, CHP units have been built by several utilities and have provided combined heat and power energy with equivalent CO2 emissions well below the proposed standard, and the commenter believed it would be counterproductive to apply the GHG standard to such CHP sources. Commenter 8952 also recommended specifically exempting simple cycle turbines that serve combined heat and power functions.
Commenter (8952) recommended exemption of district heating plants because of their net benefit within CHP installations.
Commenter (10098) opposed the EPA's inclusion of industrial, commercial and institutional combined heat and power units because combined heat and power units are energy efficient and offer significant GHG reduction benefits compared to conventional boilers and because the Administration is actively promoting combined heat and power in other contexts, and the commenter believed that it is arbitrary and capricious for EPA to impose regulations here that could discourage development of new CHP facilities. This commenter also offered methods for excluding industrial, commercial, and institutional CHP units from applicability via changes to certain definitions.
Commenter 9755 stated that the EPA's proposed regulations would thus incentivize industrial users to generate their own onsite power because of the higher costs of power delivered from the grid due to the new standards. Commenter 9755 stated when industrial users build on-site power, the utility sells less electricity over the same installed infrastructure. Commenter 9755 stated this effectively results in having the remaining commercial and residential customers paying a larger part of the infrastructure costs, which increases the overall; cost of electricity to commercial and residential ratepayers.
As described Section III.D.2 of the preamble to the final rule, the industrial CHP exemption has been significantly expanded and is now based permit restrictions limiting the amount of electricity that can be sold. The final exemption takes into account both the primary purpose and the environmental benefit of the unit. Therefore, the allowable sales is based on the design efficiency of the CHP unit. Specifically, the industrial CHP exemption is based on a permit restriction limiting annual electric sales to the unit's design efficiency multiplied by its potential electric output or 219,000 MWh, whichever is greater. This limits applicability to CHP units that sell a significant percentage of their potential electric output.  See Section III.F.2 of the preamble to the final rule for a discussion of thermal output credit. The EPA has concluded that there is no need to specifically identify waste heat to power projects. To the extent that these units meet the applicability criteria, they will be subject to the requirements of the final rule.
Commenter (9514) stated that EPA should revise its proposed rule to ensure that the individual gas combustion turbines and the HRSG at CCGT plants are not treated separately from the purposes of determining applicability or calculating emissions. The commenter stated that to reflect the agency's determination that CCGT is BSER for gas and oil-fired EGUs, EPA should set emission limits for gas- and oil- fired EGUs, including the combustion turbines and any HRSG that are associated with those turbines, based on the demonstrated performance of the best existing and anticipated new CCGTs, rather than setting separate applicability emission limits for the combustion turbines and HRSGs that make up CCGTs.
 The definition of a stationary combustion turbine includes both the turbine engine and the associated HRSG.
Biomass Fuels and the Ten Percent or Less Fossil Fuel Threshold
Commenters (3862, 8957, 9513, 9514, 9780, 10038) generally supported the EPA's proposed criteria for use of 10.0 percent fossil fuels on a 3 year rolling average basis because this criterion is consistent with the MATS rule and allows biomass-fired units to use some fossil fuels for flame stabilization without triggering applicability. Commenter 9514 recommended also including a 15.0 percent fossil fuel threshold on an annual basis. Commenter 9513 stated that EPA must resolve the ongoing question of which biomass fuels should qualify as renewable resources. Commenter 9780 stated that they supported this functional exemption for units that would run only during emergencies.
 Commenters (9198, 9592, 9733, 10100) generally supported the exclusion of biomass-fired units. Commenter 9774 stated that biomass fuels should not be regulated if co-fired with fossil fuel and should be creditable towards meeting the fossil fuel NSPS. The commenter stated that biomass CO2 emissions should not be regulated under the NSPS coal CO2 emission limit regardless of what portion is fired with coal or other fossil fuels. The commenter felt that doing so will only penalize the use of biomass energy when there are many biomass fuels, including those harvested under sustainable forestry practices that are beneficial in reducing CO2 impacts fossil fuels. The commenter believed that EPA should provide credit from the use of biomass fuels towards meeting any fossil fuel CO2 emission limitation. At a minimum, EPA should not regulate biomass CO2 emissions under the same rule as the proposed NSPS for coal-fired generation or allow states to determine the CO2 neutrality of different biomass fuels.
 Commenter (9425, 9780) supported the EPA's intention to exempt EGUs that primarily fire biomass, but this commenter believed that the final rule should include an explicit exemption for biomass units. Commenter 9596 stated that the EPA should adjust the applicability threshold for biomass co-firing.
 Commenters (9592, 10100) generally supported exclusion of biomass fired boilers but urged the EPA to adopt the biomass exemption as proposed in the 2012 proposal, which would have exempted from the NSPS biomass-fired boilers that co-fire with less than 250 MMBtu/hr of any fossil fuel. Commenters (9592, 10100) asserted that the biomass exemption in the 2012 proposal provides owners with greater operational flexibility than the current proposal's ten percent threshold. If the EPA retains the ten percent threshold, commenter 10100 supported use of a three year rolling average.
 Commenter 9194 stated that EPA's proposed modification of this exclusion to cover electric generating units burning less than 10 percent fossil fuels does not provide the flexibility afforded by the originally proposed 250 MMBtu/hr fossil fuel exemption. Commenter 9194 encouraged EPA to retain the original biomass exclusion proposal.
 Commenters (9198) opposed the proposed 10 percent threshold for fossil fuels because the commenter believed this threshold is too low and that it will significantly reduce the use of biogenic fuels. This commenter believed that the EPA should revise the proposed rule to properly account for the significant difference between fossil fuel and biogenic sources of CO2 and should increase the applicability threshold for fossil fuels to allow any EGU regulated under section 111 to make use of biogenic fuels to lower their CO2 emissions.
 Commenter 10606 believed that the proposed threshold of 10 percent for fossil fuels is too low. An EGU could fire 20 or 30 percent fossil fuel, with the remainder biomass, and still "primarily" fire biomass. NHPC does not believe it was EPA's intent to prevent new, clean, renewable, primarily biomass-fired EGUs from being constructed, but that could be the result of the Proposed Rule unless it is revised. The CO2 emissions from a biomass-fired EGU are biogenic in nature and carbon-neutral, but the CO2 emissions from a biomass-fired EGU (approximately 2,600 lb CO2/MWh) will not comply with the NSPS limit in the Proposed Rule of 1,100 lb CO2/MWh, which is based on NGCC technology. Accordingly, EPA should exempt primarily biomass fired units from the requirements in of the Proposed Rule or establish a higher threshold for fossil fuel firing.
 Commenter 9596 stated that the EPA should adjust the applicability threshold for biomass co-firing.
 Commenter 10195 requested that the EPA clarify the method an operator should use during the first three years of operations to determine if a particular unit will meet the 10 percent fossil fuel criterion prior to the end of the first three years of operations. Considering the three-year applicability criteria, commenter 10195 also asked whether or not an affected facility has a compliance obligation during the first three year period, and the commenter also asked if an affected facility does not meet the 10 percent fossil fuel criteria, from which 12-operating month rolling average compliance determinations is the affected facility excluded?
 Commenter 10136 noted that EPA asks if the 10 percent requirement for fossil fuel heat input should be recast to cover plants that were designed to burn fossil fuels. The commenter stated that making this change could mitigate the potential for companies to convert their coal-fired boilers to wood, as the commenter is doing. Commenter 10136 stated that assuming that as presently written, the rule would consider a coal-to-biomass conversion to be a new wood-burning plant and thus no longer subject to the fossil fuel-fired EGU NSPS, then making the applicability of the rule contingent on what the plant was designed to burn would ensure that such plants continued to be covered.
Commenter 9198 stated that EPA's definition of affected facilities will significantly limit use of biogenic fuels under both of its proposed rules. The commenter stated that the proposal's low applicability threshold for fossil fuel use could severely restrict the future use of biogenic fuels, particularly when coupled with EPA's proposal to treat biogenic and fossil fuel CO2 emissions similarly for compliance purposes. The combination of the 10 percent threshold with the failure to differentiate between biogenic and fossil fuel emissions will prevent the utilities from substituting lower-carbon biomass or biogas fuels as replacements for fossil fuel in new plants or potentially in existing plants.
 Commenter 8948, 8972, 9002, 9194, 9198, 9409, 9425, 9509, 9592, 9593, 9733, 9774, 10027, 10035,10045, 10051, 10131, 10606 stated that the EPA should exclude biogenic CO2 emissions as carbon neutral for applicability purposes under the rule because it would be arbitrary and capricious for EPA to regulate and treat these biogenic CO2 emissions in the same manner as fossil fuel emissions before EPA has finalized its scientific review of biogenic CO2 emissions and determined even whether they should be regulated as a pollutant under the Clean Air Act.
Commenter 9409 stated that inclusion of biogenic CO2 emissions from co-fired EGUs in the final rule would be arbitrary and capricious because the EPA acknowledged in the proposed rule pending policy decisions related to accounting for biogenic CO2 emissions from stationary sources, but, the commenter stated, the EPA inexplicably proposes to regulate biogenic CO2 emissions from co-fired EGUs in the same manner as fossil fuel CO2 emissions, with no justification. The commenter urged the EPA to defer regulation under the NSPS of biogenic CO2 emissions from co-fired EGUs at this time and to instead move forward after the broader policy on biogenic emissions is settled.
Commenter 10031 noted that while the proposal would exempt biomass boilers that meet the 90 percent threshold, it would not exempt boilers that co-fire with biomass but use more than 10 percent fossil fuel. The commenter believed biomass sources, including sources that co-fire biomass but also use more than 10 percent fossil fuel, should get credit for offsite factors related to the carbon cycle (sequestered CO2) for the biomass fuel being combusted at the stationary source (typically derived from forest-derived woody or agricultural biomass or waste materials). The commenter supported the Agency's development of an Accounting Framework to evaluate these issues. The commenter stated that EPA should not finalize this rule for Subpart Da units until it incorporates the findings of the Accounting Framework and devises an approach that would give the proper credit to sources that use biomass at any level of heat input.
 Commenter 10100 opposed EPA's suggested approach of using its Accounting Framework for Biogenic CO2 Emissions from Stationary Sources to evaluate in the future whether a particular type of biomass is carbon neutral. See 79 Fed. Reg. at 1446. The commenter stated that the Accounting Framework presents a methodology for applying an "adjustment" to a source's CO2 emissions based on a site-specific analysis of how the biomass feedstock was grown and harvested. The commenter stated it would be problematic to use the Accounting Framework in practice for permitting, emission reporting, or calculating compliance obligations. The commenter stated every new biomass EGU would be required to perform a lengthy and expensive study applying the methodology, seek EPA approval of its conclusions and proposed adjustment factor, and presumably repeat this entire process any time there was a change in the plant's feedstock. The commenter believed that this introduces significant uncertainty for investment in biomass power plants.
Commenter 10100 opposed use of the Accounting Framework for Biogenic CO2 Emissions from Stationary Sources to evaluate whether or not a particular type of biomass is carbon neutral because the framework would be problematic to apply in practice as every new biomass EGU would be required to perform a lengthy and expensive study applying the methodology, seek federal approval, and repeat this process for each change in feedstock; the commenter believed that such an evaluation would introduce significant uncertainty for investments in biomass power plants.
Commenter 9676 stated that EPA cannot set what is clearly an arbitrary threshold until the Agency completes a rulemaking on the GHG accounting of biogenic emissions. To do so would ignore the very rulemaking on biogenic emissions that is now pending.
Commenter 10045 noted that a commenter during the rulemaking that led to the 2009 Endangerment and Contribution Findings asked EPA to exclude biogenic CO2 emissions from the Findings on the grounds that they do not contribute to endangerment of health and welfare. In its response-to-comments document, EPA rejected that request because: "[A]ll CO2 emissions, regardless of source, influence radiative forcing equally once it reaches the atmosphere and therefore there is no distinction between biogenic and non-biogenic CO2 regarding the CO2 and other well-mixed GHGs within the definition of air pollution that is reasonably anticipated to endanger public health and welfare." The commenter strenuously disagreed with that statement insofar as Crop-Derived CO2 is concerned, and believed it was a mistake. The commenter stated the author of the response failed to recognize that the definitional foundation of the 2009 Findings, i.e., the 2009 GHG emissions inventory and the underlying IPCC guidelines used to develop that inventory, contained the science-based determination that Crop-Derived CO2 is inconsequential to the global warming process. The commenter stated that emissions of Crop-Derived CO2 are indeed different as a scientific matter because they merely return to the atmosphere carbon atoms that were present in the atmosphere only a short time beforehand. Moreover, EPA otherwise consistently and fundamentally recognized and adopted that principle in its 2009 Endangerment and Contribution Findings. Commenter 10045 also stated that even if crop-derived CO2 contributed to global warming, which the commenter insisted was not the case, then it would be a de minimis contribution and therefore irrelevant. The commenter stated that if EPA were to decline to exclude crop-derived CO2 categorically, then the EPA should complete its review of SAB's Critique of EPA's Biogenic Accounting Framework during the instant NSPS rulemaking and incorporate a default BAF of Zero for Crop-Derived CO2 into the NSPSs' compliance system. Commenter 10045 also asked EPA to confirm expressly that an exclusion keeps the NSPSs from triggering applicability of the PSD and Title V permitting programs to emissions of Crop-Derived CO2.
 Commenter 10045 stated that the indirect (off-site) emissions of biogenic CO2 associated with an EGU's combustion of annual herbaceous crop-derived fuel are harmless. Applying the conservative assumption that conservation tillage practices are employed in producing the corn and corn stover, a study cited in the comment found under all three methods ((i) life cycle biogenic carbon balance, (ii) mass balance, and (iii) EPA's Biogenic Accounting Framework), including notably EPA's Biogenic Accounting Framework, that the indirect biogenic carbon emissions were net negative, i.e., that the full biogenic carbon cycle yields a net sequestration of carbon, due primarily to the generation of biochar.
 Commenter 10125 stated that the rule will actually increase emissions if it drives construction of biopower plants. The commenter stated that coal plants that co-fire wood produce more emissions than traditional coal plants. The commenter stated that it is therefore a good thing that the rule counts biogenic emissions toward facility totals, since treating wood as an emissions mitigation strategy is completely counterproductive. The commenter also stated that failure of EPA to act and recognize the impacts of bioenergy on greenhouse gas emissions could result in widespread forest degradation and significantly increased greenhouse gas emissions from the power sector.
 Commenters 10025, 10106, 10119, 10136 stated that EPA must establish credible greenhouse gas performance standards for biomass power plants. As it did in the 2012 Proposed Rule, commenters stated EPA has once again failed to propose greenhouse gas performance standards applicable to EGUs that primarily fire biomass. These facilities can be very carbon-intensive, emitting far more CO2 than coal-fired facilities on a pounds-per-MWh basis; indeed, measured at the smokestack, replacing fossil fuels with biomass actually increases CO2 emissions. The commenter stated that in light of the high levels of CO2 emissions from biomass-fired facilities - emissions that warm the climate and endanger health and welfare, regardless of their biogenic nature - EPA must either include biomass-fired EGUs within the scope of the present standard or determine a separate standard based on BSER for these facilities.
Commenter 9198 commented on the use of biomass as fuel for combustion turbines: "Energy produced from forest, agricultural and MSW biomass should be one component of an overall bioenergy strategy to reduce emissions of CO2 from fossil fuels, and EPA's rules should advance rather than hinder that goal. We recognize that statutory and regulatory differences can result in significant dissimilarities in program structure and operation. With respect to the EPA's proposed approach to biogenic CO2 accounting under the 111(b) program; however, we are deeply concerned that EPA's underlying view of the benefits and value of developing biogas and biomass projects is not intellectually consistent. EPA's proposal to treat biogenic and fossil fuel-based emissions similarly in determining compliance with the proposed GHG NSPS contradicts the Agency's own lifecycle assessments for renewable transportation fuels and other renewable energy initiatives. [The commenter] is concerned that EPA's proposal to consider biogenic and fossil fuel GHG emissions as equivalent will preclude the Agency's' ability to develop cost-effective and flexible compliance options for any power plant, new or existing. In short, this approach undermines the fundamental premise of the RFS2 program and the goals of Congressional and Administration programs to promote renewable energy and fuel production. For these reasons, we strongly urge EPA to reconsider the proposed approach and to provide a level playing field for biogas and MSW biomass and other renewable energy projects. Such an approach is reasonable, consistent, and harmonizes with EPA's efforts to reduce CO2 emissions from power plants."
Dedicated non-fossil units subject to a permit restricting the use of fossil fuel to 10 percent or less of the annual capacity factor are subject to the requirements of this final rule. See section III.D.1 of the NSPS preamble for discussion of dedicated non-fossil fuel units.

EPA developed the revised draft report, Framework for Assessing Biogenic CO2 Emissions from Stationary Sources, to continue advancing our understanding of the role the use of biomass can play in strategies to address greenhouse gas emissions. Specifically, the Framework was developed as a policy-neutral framework for assessing biogenic CO2 emissions from stationary sources -- it was not developed as technical guidance in conjunction with any specific policy or program. The revised Framework, and the EPA's Science Advisory Board (SAB) peer review of the 2011 Draft Framework, finds that it is not scientifically valid to assume that all biogenic feedstocks are "carbon neutral" and that the net biogenic CO2 atmospheric contribution of different biogenic feedstocks generally depends on various factors related to feedstock characteristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production. For more information regarding the Framework, see: http://epa.gov/climatechange/ghgemissions/biogenic-emissions.html
Commenter 9198 commented on the use of landfill gas as fuel: "It is difficult to reconcile EPA's approach in the 111(b) proposal with the White House's commitment to reduce further methane emissions. If the climate impacts of LFG emissions are not properly accounted for, biogas and MSW energy projects will be unable to demonstrate CO2 reductions and would thus be, ineligible compliance options to assist power plants regulated under Section 111. If EPA treats renewable biogas and MSW differently than other renewable energy sources, it will eliminate these proven, reliable and cost-effective compliance options under the new source performance standard or potentially in state plans developed under 111(d).  EPA's Office of Transportation and Air Quality has evaluated MSW and landfill gas as feedstocks for the production of renewable transportation fuels, and concluded that it is appropriate to treat the biogenic portion of the MSW and LFG feedstocks as carbon-neutral. Landfill gas is now considered an advanced biofuel, moreover, in recognition of its reduction of lifecycle GHG emissions of at least 60 percent below the petroleum fuel it replaces, and because it is largely cellulosic in derivation, EPA has recently proposed that it be reclassified as a cellulosic biofuel. The biogenic portion of MSW that has undergone reasonably practicable separation of recyclable materials has likewise been determined to be a renewable feedstock for low carbon fuels, such as cellulosic ethanol. Without recognition of the different GHG impacts of these biogenic emissions, stationary and mobile sources of GHG will have no incentive to switch to renewable, lower carbon energy sources."
Commenter 10131 supported exemption of units that burn landfill gas because, the commenter asserted, combustion of landfill gas does not contribute to global climate change. The commenter opposed provisions that apply the same accounting method for biogenic CO2 emissions as for fossil CO2 emissions.
 Commenter 10027 urged EPA to develop accounting procedures that assign the CO2 released from the decomposition of biogenic waste in landfills, compost facilities, or anaerobic digesters a biogenic accounting factor (BAF) of zero. Commenter 10027 stated this assignment is consistent with the recommendations of the Science Advisory Board (SAB) impaneled on this subject. Commenter 10027 stated the SAB also noted that management of municipal solid waste (MSW) and landfill gas (LFG) posed no land use changes or reductions in carbon stocks not already attributed to the manufacturer of the products subsequently discarded.
The applicability criteria in the final rule includes combustion turbines that are capable of selling greater than 25 MW-n to the grid, are connected to a natural gas pipeline, and that are not subject to a permit resting annual fossil fuel use to 10 percent or less of the annual capacity factor. A landfill gas-fired unit not that does not meet any one of these criteria would not be subject to the requirements of the final rule. In the unlikely event that a landfill gas (or anaerobic digester gas)-fired unit meets the applicability criteria, the applicable emission standard will be the multi-fuel-fired unit standard. This standard is based on the use of clean fuels. These facilities would use the procedures in part 98 of this part to determine the average net CO2 emission rate for the fuels burned during the 12-operaitng-month period.

EPA developed the revised draft report, Framework for Assessing Biogenic CO2 Emissions from Stationary Sources, to continue advancing our understanding of the role the use of biomass can play in strategies to address greenhouse gas emissions. Specifically, the Framework was developed as a policy-neutral framework for assessing biogenic CO2 emissions from stationary sources -- it was not developed as technical guidance in conjunction with any specific policy or program. The revised Framework, and the EPA's Science Advisory Board (SAB) peer review of the 2011 Draft Framework, finds that it is not scientifically valid to assume that all biogenic feedstocks are "carbon neutral" and that the net biogenic CO2 atmospheric contribution of different biogenic feedstocks generally depends on various factors related to feedstock characteristics, production, processing and combustion practices, and, in some cases, what would happen to that feedstock and the related biogenic emissions if not used for energy production. For more information regarding the Framework, see: http://epa.gov/climatechange/ghgemissions/biogenic-emissions.html

Codified Rule Under Subpart TTTT and KKKK, and Applicability for Subpart KKKK Units
Commenter (4867) pointed out the benefits of codifying applicability of the standard under a single NSPS source category (proposed new subpart TTTT) rather than under separate source categories (subparts Da and KKKK). Commenter 4867 believed that the decision to codify applicability of the efficiency standard to both coal and gas-fired EGUs under a single subpart (i.e., under a single section 111(b) category) has far-reaching implications for future existing source guidelines put forth under section 111(d), because the commenter believed, that grouping coal- and gas-fired EGUs into a single category is a pre-requisite for deployment of GHG trading programs within state implementation plans under section 111(d).
Commenter 7540 stated that the use of Existing Subparts EPA proposes separate standards based on EGU type; one for units regulated under Subpart Da and two for units regulated under Subpart KKKK. Commenter supported separate standards for sources currently regulated under Da and KKKK, provided 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. Commenter stated however, if EPA determines 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 Clean Energy Group would support development of a new subpart (TTTT) that includes the proposed performance standards for new boilers and combustion turbines. In supporting the maintenance of this flexibility, the commenter was not recommending a specific structure for an existing source standard.
See Section III.B of the preamble for a discussion of why the EPA is finalizing a new subpart TTTT for this NSPS rulemaking.
Commenter 9427 stated that under Subpart KKKK, the EPA should incorporate applicability provisions for configurations with two combustion turbine-generators and a common steam turbine-generator so that applicability and compliance can be determined on a combined basis if this option is selected by the operator. Under this option, the commenter suggested that the applicability criteria for such "2X1" configurations under proposed section 60.4305 would likewise be determined on a combined basis, doubling the actual electric output applicability threshold to reflect two combustion turbines.
 Commenter 9427, a municipal electric power authority, stated that the final rule should not require a plan approved by the administrator when apportionment is used as proposed under section 60.4373(e) because a common design is where steam from several heat recovery steam generators (HRSGs) associated with stationary combustion turbines is directed to a single steam turbine that drives a steam turbine electric generator. The commenter stated that the regulatory text should be clarified by revising it to read "serve a common electric generator or a common steam turbine with an electric generator..." The commenter went on to say that stationary combustion turbines are already required by Part 75 to measure heat input, including heat input to duct burners at associated HRSGs. The commenter stated allocating gross output (MWh) of a common steam turbine electric generator by using heat input to combustion turbines and associated HRSGs would be a very straightforward process and should be allowed without the need for a plan approved by the Administrator, and the commenter recommended that the end of the first sentence in proposed 60.4373(d) be revised by adding the words "and any associated steam turbine electric generator."
For this rulemaking, the affected facility is each stationary combustion turbine. See definition in section 60.5580. We understand the point raised by the commenter, as many NGCC units are being constructed in two-on-one and three-on-one configurations. In the future, we may allow emissions averaging for power blocks, but for now, we are requiring that generation (gross or net) be apportioned to the units according to the fraction of total steam load or the fraction of combined heat input. See section 60.5535 (e) of the rule for the compliance and monitoring procedures for two or more affected EGUs that share a single steam generator.
Commenter 9591 urged the EPA to consider interactions between the proposed Subpart KKKK revisions for criteria pollutants and the proposed provisions for CO2 to avoid conflict with this rule's intended focus on entirely new units. The commenter stated that the definition of stationary combustion turbine proposed in August 2012 for the criteria pollutant amendments is inconsistent with the definition in the proposed standard for CO2. The commenter urged the EPA to ensure these revisions do not conflict, nor have unintended effects.
The EPA notes that the proposed August 2012 amendments to the criteria pollutant NSPS for combustion turbines has not been finalized. Further, while the EPA often tries to harmonize different rulemakings, this is not always practical or appropriate. The EPA will consider the requirements in this final rule when amendments are finalized to the combustion turbine criteria pollutant NSPS.
Commenter 10681, a permitting authority with numerous small and medium sized simple-cycle generators used for load following and intermediate loads, considered the proposed applicability criteria in conjunction with current permit limits on hours of operations; this commenter anticipates that the proposed rule will result in deployment of many more of the smaller combustion turbines and large reciprocating engines due to their simplicity to permit, install, and operate, in spite of their higher lb CO2/MWh emission rates. This commenter believed that that environmentally, the use of combustion turbines is superior to the use of internal combustion engines for generation of electricity. This commenter also suggested that the EPA continue to utilize the current definitions of simple and combined cycle turbines already contained in subpart KKKK and used for applicability.
The EPA disagrees that the requirements of this final rule will discourage the development of new simple cycle combustion turbines. The flexibility provided by the sliding-scale approach and the non-base load emission standard will minimize the burden for new simple cycle combustion turbines.
Commenter 1637 urged the EPA to give greater weight to the notion of a "best SYSTEM of emission reduction" as required by Clean Air Act Section 111(a)(1). Commenter stated that EPA should take that to include the upstream supply system of the fuel. Commenter stated that it is unclear that "affected facility" under NSPS Subpart OOOO includes more than those involving hydraulic fracturing or that Subparts VV or VVa extend to all natural gas supply sources, upstream to the wellhead. Commenter noted that in addition EPA should proceed to develop and issue for comment a proposal for regulation under Section 111(d) of greenhouse gas (GHG) emission leaks from the existing supply systems for natural gas. Commenter noted that in addition EPA should require that each affected facility under the proposed additions to Subpart KKKK should be required to obtain from their natural gas supplier a copy of their reports under the GHG reporting rule 40CFR98 Subpart W, in order to calculate the equivalent CO2 emissions from leaks in their supply system for the gas they receive and to report to EPA those equivalent emissions along with their reporting of their own emissions. Commenter noted that they are not advocating that EPA must include these equivalent emissions in their calculation of their allowed emissions, but the commenter believed that EPA must establish baselines in order to meet the mandate of Section 111(a)(1) to allow "any cleaning of fuel or reduction in the pollution characteristics of the fuel after extraction and prior to combustion may be credited, as determined by the Administrator, to a source that burns such fuel."
The EPA disagrees with this comment. The "system" in BSER refers to a system that reduces emissions from the source, not a system of emissions that cumulatively results from upstream and downstream activities. As such, the EPA is not regulating other sources of emissions besides affected EGUs in this rulemaking.


[Federal Register Volume 78, Number 124 (Thursday, June 27, 2013)]
[Rules and Regulations]
[Pages 38580-38582]
[FR Doc No: 2013-15377]

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DEPARTMENT OF HOMELAND SECURITY

Coast Guard

33 CFR Part 100

[Docket No. USCG-2013-0368]
RIN 1625-AA08

Special Local Regulation; Tall Ships Celebration Bay City, Bay
City, MI

AGENCY: Coast Guard, DHS.

ACTION: Temporary final rule.

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SUMMARY: The Coast Guard is establishing a temporary special local
regulation for a tall ships parade located in the Captain of the Port
Detroit Zone. This action is necessary and intended to ensure safety of
life and property on navigable waters during this event. This special
local regulation will establish restrictions upon, and control movement
of, vessels in a portion of the Captain of the Port Detroit Zone.
During the enforcement period, no person or vessel may enter the
regulated area without permission of the Captain of the Port.

DATES: This rule is effective from 12:30 p.m. until 4:30 p.m. on July
11, 2013.

ADDRESSES: Documents mentioned in this preamble are part of docket
[USCG-2013-0368]. To view documents mentioned in this preamble as being
available in the docket, go to http://www.regulations.gov, type the
docket number in the ``SEARCH'' box, and click ``Search.'' You may
visit the Docket Management Facility, Department of Transportation,
West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE.,
Washington, DC 20590, between 9 a.m. and 5 p.m., Monday through Friday,
except Federal holidays.

FOR FURTHER INFORMATION CONTACT: If you have questions on this
temporary rule, call or email LT Adrian Palomeque, Prevention
Department, Sector Detroit, Coast Guard; telephone<PHONE_NUMBER>,
email<EMAIL_ADDRESS>If you have questions on viewing the
docket, call Barbara Hairston, Program Manager, Docket Operations,
telephone<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Table of Acronyms

DHS Department of Homeland Security
FR Federal Register
NPRM Notice of Proposed Rulemaking

A. Regulatory Information

    The Coast Guard is issuing this temporary final rule without prior
notice and opportunity to comment pursuant to authority under section
4(a) of the Administrative Procedure Act (APA) (5 U.S.C. 553(b)). This
provision authorizes an agency to issue a rule without prior notice and
opportunity to comment when the agency for good cause finds that those
procedures are ``impracticable, unnecessary, or contrary to the public
interest.'' Under 5 U.S.C. 553(b)(B), the Coast Guard finds that good
cause exists for not publishing a notice of proposed rulemaking (NPRM)
with respect to this rule because doing so would be impracticable. The
final details for this Tall Ships parade were not known to the Coast
Guard until there was insufficient time remaining before the event to
publish an NPRM. Thus, delaying the effective date of this rule to wait
for a comment period to run would be impracticable because it would
inhibit the Coast Guard's ability to protect spectators, participants,
and vessels from the hazards associated with this event.
    Under 5 U.S.C. 553(d)(3), the Coast Guard finds that good cause
exists for making this rule effective less than 30 days after
publication in the Federal Register. For the same reasons discussed in
the preceding paragraph, waiting for a 30 day notice period run would
be impracticable and contrary to the public interest.
    Although this is the Coast Guard's first regulatory act for the
celebration specific to Bay City, MI, the Coast Guard recently
published a separate NPRM in the Federal Register seeking to establish
safety zones around each tall ship participating in various events
throughout the Great Lakes this summer, to include the Tall Ships
Celebration Bay City. Specifically, on May 1, 2013, the Coast Guard
published in the Federal Register an NPRM titled Safety Zone; Tall Ship
Safety Zones; War of 1812 Bicentennial Commemoration, Great Lakes (78
FR 25410), proposing to establish temporary safety zones around each of
the twenty-one tall ships participating in the Tall Ships Challenge
Great Lakes 2013 from June 13, 2013 to September 17, 2013.

B. Basis and Purpose

    Between 12:30 p.m. until 4:30 p.m. on July 11, 2013, the Tall Ships
Celebration Bay City 2013 parade will take place in a portion of
Saginaw Bay and the Saginaw River. This portion of waterway will need
to be clear of vessel traffic during the parade.
    Even though the Coast Guard has separately proposed a 100 yards
radius safety zone around each tall ship participating in events
throughout the Great Lakes, to include Bay City's celebration, the
Captain of the Port Detroit has determined that these safety zones will
be insufficient on their own to safeguard navigational safety in a
portion of Saginaw Bay and the Saginaw River during the Tall Ships
Celebration parade on July 11, 2013. The high possibility that tall
ships participating in the parade on July 11, 2013 will encounter
recreational and commercial vessels in the relatively narrow navigable
channel of the Saginaw River, compounded with the decreased
maneuverability of these tall ships, poses extra and unusual hazards to
public safety and property. Moreover, the Captain of the Port Detroit
has determined that the existing navigational rules of the road are not
sufficient to protect the public against these extra and unusual
hazards. Thus, the Captain of the Port Detroit has determined that
establishing a Special Local Regulation, pursuant to the authority in
33 U.S.C. 1233, throughout the parade course will help ensure the
safety of life during this event.

C. Discussion of Rule

    In light of the aforesaid hazards, the Captain of the Port Detroit
has determined that a special local regulation is necessary to ensure
the safety of spectators, vessels, and participants. This special local
regulation will be enforced from 12:30 p.m. until 4:30 p.m. on July 11,
2013. The special local regulation will encompass all waters throughout
the federal navigational channel of Saginaw Bay from Light Buoy 11 at
position 43[deg]43'54'' N, 083[deg]46'52'' W and Light 12 at position
43[deg]43'56'' N, 083[deg]46'57'' W to the Saginaw River, and on all
waters of the Saginaw River from its mouth to the Veterans Memorial
Bridge in Bay City, MI at position 43[deg]35'46'' N, 083[deg]53'36'' W.
All geographic coordinates are North American Datum of 1983 (NAD 83).
Entry into, transiting, or anchoring within the proposed regulated area
while it is being enforced is prohibited unless authorized by the
authority of the Captain of the Port Detroit or his designated on-scene
representative. The

Captain of the Port or his designated on-scene representative may be
contacted via VHF Channel 16.

D. Regulatory Analyses

    We developed this rule after considering numerous statutes and
executive orders related to rulemaking. Below we summarize our analyses
based on these statutes or executive orders.

1. Regulatory Planning and Review

    This rule is not a significant regulatory action under section 3(f)
of Executive Order 12866, Regulatory Planning and Review, as
supplemented by Executive Order 13563, Improving Regulation and
Regulatory Review, and does not require an assessment of potential
costs and benefits under section 6(a)(3) of Executive Order 12866 or
under section 1 of Executive Order 13563. The Office of Management and
Budget has not reviewed it under that Orders. It is not ``significant''
under the regulatory policies and procedures of the Department of
Homeland Security (DHS). We conclude that this rule is not a
significant regulatory action because we anticipate that it will have
minimal impact on the economy, will not interfere with other agencies,
will not adversely alter the budget of any grant or loan recipients,
and will not raise any novel legal or policy issues.
    The Coast Guard's use of this special local regulation will be of
relatively small size and short duration, and it is designed to
minimize its impact on navigation. Furthermore, vessels may, when
circumstances allow, obtain permission from the Captain of the Port to
transit through the area affected by this special local regulation.
Overall, the Coast Guard expects minimal impact to vessel movement from
the enforcement of this special local regulation.

2. Impact on Small Entities

    The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601-612, as
amended, requires federal agencies to consider the potential impact of
regulations on small entities during rulemaking. The term ``small
entities'' comprises small businesses, not-for-profit organizations
that are independently owned and operated and are not dominant in their
fields, and governmental jurisdictions with populations of less than
50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this rule
will not have a significant economic impact on a substantial number of
small entities.
    This rule will affect the following entities, some of which might
be small entities: the owners or operators of vessels intending to
transit or anchor in a portion of Saginaw Bay beginning at Light Buoy
11 at position 43[deg]43'54'' N, 083[deg]46'52'' W and Light 12 at
position 43[deg]43'56'' N, 083[deg]46'57'' W to the Saginaw River, and
on a portion of the Saginaw River from its mouth to the Veterans
Memorial Bridge in Bay City, MI at position 43[deg]35'46'' N,
083[deg]53'36'' W between 12:30 p.m. and 4:30 p.m. on July 11, 2013.
    This special local regulation will not have a significant economic
impact on a substantial number of small entities for the following
reasons: This regulated area will only be in effect and enforced for
four hours on one day. Additional vessel traffic may be allowed to pass
through the zone with the permission of the Captain of the Port. The
Captain of the Port can be reached via VHF channel 16. The Coast Guard
will give notice to the public via a Broadcast Notice to Mariners that
the regulation is in effect, allowing vessel owners and operators to
plan accordingly.

3. Assistance for Small Entities

    Under section 213(a) of the Small Business Regulatory Enforcement
Fairness Act of 1996 (Pub. L. 104-121), we want to assist small
entities in understanding this rule. If this rule would affect your
small business, organization, or governmental jurisdiction and you have
questions concerning its provisions or options for compliance, please
contact the person listed in the FOR FURTHER INFORMATION CONTACT
section above.
    Small businesses may send comments on the actions of Federal
employees who enforce, or otherwise determine compliance with, Federal
regulations to the Small Business and Agriculture Regulatory
Enforcement Ombudsman and the Regional Small Business Regulatory
Fairness Boards. The Ombudsman evaluates these actions annually and
rates each agency's responsiveness to small business. If you wish to
comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR
(1-888-734-3247). The Coast Guard will not retaliate against small
entities that question or complain about this rule or any policy or
action of the Coast Guard.

4. Collection of Information

    This rule calls for no new collection of information under the
Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

5. Federalism

    A rule has implications for federalism under Executive Order 13132,
Federalism, if it has a substantial direct effect on States, on the
relationship between the national government and the States, or on the
distribution of power and responsibilities among the various levels of
government. We have analyzed this rule under that Order and determined
that this rule does not have implications for federalism.

6. Protest Activities

    The Coast Guard respects the First Amendment rights of protesters.
Protesters are asked to contact the person listed in the FOR FURTHER
INFORMATION CONTACT section to coordinate protest activities so that
your message can be received without jeopardizing the safety or
security of people, places or vessels.

7. Unfunded Mandates Reform Act

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538)
requires Federal agencies to assess the effects of their discretionary
regulatory actions. In particular, the Act addresses actions that may
result in the expenditure by a State, local, or tribal government, in
the aggregate, or by the private sector of $100,000,000 (adjusted for
inflation) or more in any one year. Though this rule will not result in
such expenditure, we do discuss the effects of this rule elsewhere in
this preamble.

8. Taking of Private Property

    This rule will not cause a taking of private property or otherwise
have taking implications under Executive Order 12630, Governmental
Actions and Interference with Constitutionally Protected Property
Rights.

9. Civil Justice Reform

    This rule meets applicable standards in sections 3(a) and 3(b)(2)
of Executive Order 12988, Civil Justice Reform, to minimize litigation,
eliminate ambiguity, and reduce burden.

10. Protection of Children From Environmental Health Risks

    We have analyzed this rule under Executive Order 13045, Protection
of Children from Environmental Health Risks and Safety Risks. This rule
is not an economically significant rule and does not create an
environmental risk to health or risk to safety that may
disproportionately affect children.

11. Indian Tribal Governments

    This rule does not have tribal implications under Executive Order
13175, Consultation and Coordination with Indian Tribal Governments,
because it does not have a substantial direct effect on one or more
Indian tribes, on the relationship between the Federal Government and
Indian tribes,

or on the distribution of power and responsibilities between the
Federal Government and Indian tribes.

12. Energy Effects

    This action is not a ``significant energy action'' under Executive
Order 13211, Actions Concerning Regulations That Significantly Affect
Energy Supply, Distribution, or Use.

13. Technical Standards

    This rule does not use technical standards. Therefore, we did not
consider the use of voluntary consensus standards.

14. Environment

    We have analyzed this rule under Department of Homeland Security
Management Directive 023-01 and Commandant Instruction M16475.lD, which
guide the Coast Guard in complying with the National Environmental
Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f), and have concluded
this action is one of a category of actions which do not individually
or cumulatively have a significant effect on the human environment.
This rule involves a special local regulation issued in conjunction
with a regatta or marine parade, and, therefore it is categorically
excluded from further review under paragraph (34)(h) of Figure 2-1 of
the Commandant Instruction. During the annual permitting process for
this event an environmental analysis was conducted, and thus, no
preliminary environmental analysis checklist or Categorical Exclusion
Determination are required for this rulemaking action.

List of Subjects in 33 CFR Part 100

    Marine safety, Navigation (water), Reporting and recordkeeping
requirements, Waterways.

    For the reasons discussed in the preamble, the Coast Guard amends
33 CFR part 100 as follows:

PART 100--SAFETY OF LIFE ON NAVIGABLE WATERS

0
1. The authority citation for part 100 continues to read as follows:

    Authority: 33 U.S.C. 1233.

0
2. Add Sec.  100.T09-0368 to read as follows:

Sec.  100.T09-0368  Special Local Regulation; Tall Ships Celebration
Bay City, Bay City, MI.

    (a) Regulated area. All waters of the federal navigational channel
of Saginaw Bay from Light Buoy 11 at position 43[deg]43'54'' N,
083[deg]46'52'' W and Light 12 at position 43[deg]43'56'' N,
083[deg]46'57'' W, to the Saginaw River, and all waters of the Saginaw
River from its mouth to the Veterans Memorial Bridge in Bay City, MI at
position 43[deg]35'46'' N, 083[deg]53'36'' W. All geographic
coordinates are North American Datum of 1983 (NAD 83).
    (b) Effective and enforcement period. This special local regulation
is effective and will be enforced from 12:30 p.m. until 4:30 p.m. on
July 11, 2013. The Captain of the Port Detroit may suspend enforcement
of this special local regulation at any time. In the event that the
enforcement is ended early, the Captain of the Port Detroit will notify
the public via Broadcast Notice to Mariners.
    (c) Regulations. (1) No vessel may enter, transit through, or
anchor within the regulated area unless authorized by the Captain of
the Port Detroit, or his designated on-scene representative.
    (2) The ``on-scene representative'' of the Captain of the Port,
Sector Detroit is any Coast Guard commissioned, warrant or petty
officer or a Federal, State, or local law enforcement officer
designated by or assisting the Captain of the Port, Sector Detroit to
act on his behalf.
    (3) Vessel operators desiring to enter or operate within the
regulated area shall contact the Captain of the Port Detroit or his on-
scene representative to obtain permission to do so. The Captain of the
Port Detroit or his on-scene representative may be contacted via VHF
Channel 16 or at<PHONE_NUMBER>. Vessel operators given permission to
enter or operate in the regulated area must comply with all directions
given to them by the Captain of the Port Detroit, or his on-scene
representative.

    Dated: June 10, 2013.
J.E. Ogden,
Captain, U.S. Coast Guard, Captain of the Port Detroit.
[FR Doc. 2013-15377 Filed 6-26-13; 8:45 am]
BILLING CODE 9110-04-P


[Federal Register Volume 85, Number 174 (Tuesday, September 8, 2020)]
[Notices]
[Pages 55469-55470]
[FR Doc No: 2020-19729]

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DEPARTMENT OF HOMELAND SECURITY

Federal Emergency Management Agency

[Docket ID FEMA-2020-0002]

Changes in Flood Hazard Determinations

AGENCY: Federal Emergency Management Agency; DHS.

ACTION: Notice; correction.

-----------------------------------------------------------------------

SUMMARY: On August 21, 2020, FEMA published in the Federal Register a
changes in flood hazard determination notice that contained an
erroneous table. This notice provides corrections to that table, to be
used in lieu of the information published at 85 FR 41608. The table
provided here represents the changes in flood hazard determinations and
communities affected for Unincorporated Areas of Kaufman County, Texas.

DATES: These flood hazard determinations will be finalized on the dates
listed in the table below and revise the FIRM panels and FIS report in
effect prior to this determination for the listed communities.

ADDRESSES: The affected communities are listed in the table below.
Revised flood hazard information for each community is available for
inspection at both the online location and the respective community map
repository address listed in the table below. Additionally, the current
effective FIRM and FIS report for each community are accessible online
through the FEMA Map Service Center at https://msc.fema.gov for
comparison.
    Submit comments and/or appeals to the Chief Executive Officer of
the community as listed in the table below.

FOR FURTHER INFORMATION CONTACT: Rick Sacbibit, Chief, Engineering
Services Branch, Federal Insurance and Mitigation Administration, FEMA,
400 C Street SW, Washington, DC 20472,<PHONE_NUMBER>, or (email)
<EMAIL_ADDRESS>or visit the FEMA Mapping and Insurance
eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html.

SUPPLEMENTARY INFORMATION: The specific flood hazard determinations are
not described for each community in this notice. However, the online
location and local community map repository address where the flood
hazard determination information is available for inspection is
provided.
    Any request for reconsideration of flood hazard determinations must
be submitted to the Chief Executive Officer of the community as listed
in the table below.
    The modifications are made pursuant to section 201 of the Flood
Disaster Protection Act of 1973, 42 U.S.C. 4105, and are in accordance
with the National Flood Insurance Act of 1968, 42 U.S.C. 4001 et seq.,
and with 44 CFR part 65.
    The FIRM and FIS report are the basis of the floodplain management
measures that the community is required either to adopt or to show
evidence of having in effect in order to qualify or remain qualified
for participation in the National Flood Insurance Program (NFIP).
    These flood hazard determinations, together with the floodplain
management criteria required by 44 CFR 60.3, are the minimum that are
required. They should not be construed to mean that the community must
change any existing ordinances that are more stringent in their
floodplain management requirements. The community may at any time enact
stricter requirements of its own or pursuant to policies established by
other Federal, State, or regional entities. The flood hazard
determinations are in accordance with 44 CFR 65.4.

Correction

    In the changes in flood hazard determination notice published at 85
FR 41608 in the August 21, 2020 issue of the Federal Register, FEMA
published a table with erroneous information. This table contained
inaccurate case number for Unincorporated Areas of Kaufman County,
Texas.
    In this document, FEMA is publishing a table containing the
accurate information. The information provided below should be used in
lieu of that previously published.

(Catalog of Federal Domestic Assistance No. 97.022, ``Flood
Insurance.'')

Michael M. Grimm,
Assistant Administrator for Risk Management, Department of Homeland
Security, Federal Emergency Management Agency.

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                                Location and     Chief executive  officer
      State and county            case No.             of community            Community map  repository         Date of  modification     Community No.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Texas: Kaufman (FEMA Docket   Unincorporated    The Honorable Hal          Kaufman County Development         Jul. 6, 2020..............          480411
 No.: B-2023)..                areas of          Richards Kaufman County    Services Department 106 West
                               Kaufman County    Judge 100 West Mulberry    Grove Street Kaufman, TX 75142.
                               (20-06-0329P).    Street Kaufman, TX
                                                 75142.
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[FR Doc. 2020-19729 Filed 9-4-20; 8:45 am]
BILLING CODE 9110-12-P