Document ID: EPA-HQ-OAR-2013-0495-11864
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2015-10-23T04:00Z

Chapter 5
Applicability to New EGUs, IGCC, and CTs
Contents
5.1	New EGUs, IGCC, and CTs	2
5.2	Prospective Applicability Criterion - Intended Purpose	23
5.3	Retrospective Applicability Criteria - General	24
5.4	One-third Sales Criterion	27
5.5	Integrated Equipment	44
5.6	Biomass Fuels and the Ten Percent or Less Fossil Fuel Threshold	49
5.7	Codified Rule Under Subpart TTTT and KKKK, and Applicability for Subpart KKKK Units		55

 New EGUs, IGCC, and CTs 
Commenters (8995, 10869) supported the overall applicability approach proposed by the EPA, and commenter 10869 found that the proposal included commonsense exclusions that are fair and do not undermine the overall integrity of the standards.
Commenter (10103) stated that they generally support the proposed requirements for subcategories of new sources of fossil fuel-fired EGUs. The commenter agreed that electric power companies will most likely choose to build new EGUs that conform to the regulatory requirements of this proposal because of existing and expected market conditions. 
Commenter (10098) opposed the competing alternative applicability provisions presented in the proposed rule text and preamble. This commenter stated that the EPA had proposed this Section 111 standard prematurely, and the commenter believed the standard is counterproductive in the context of an NSPS rulemaking because the applicability date of NSPS standards is established as the date of proposal. However, this commenter believed, given all of the competing provisions in the proposal, it is impossible to know whether certain EGU projects will meet the various applicability criteria considered in the proposal package, such as whether applicability will be based on gross or net output or whether the applicability threshold will be a 33 or 40 percent sales criterion. Commenter 10098 believed that such competing alternatives should be publicly vetted through an advanced notice of proposed rulemaking rather than in an action that sets the applicability date.
Commenter (8937) stated that the applicability date for the proposed rule was not clearly indicated in the federal register and requested that the EPA clarify the applicability date as soon as possible.
Commenter 9499 stated that EGUs that commence construction within 12 months of the effective date of the proposed rule or units for which permit applications have already been filed should be exempt from the EPA's proposed rule because the commenter believed that it is not equitable to adopt new regulations that become effective in a time frame that does not allow generation owners time to adapt long range plans to emergent requirements. 

The EPA appreciates the support of those who favored the proposed applicability approach, but the EPA has decided to finalize a variation of the broad applicability approach on which we sought comment instead. In regards to the applicability date, the Clean Air Act requires compliance as of the date that the proposal is published in the Federal Register. This approach limits the ability of developers to commence construction between the proposal and the final rule simple to avoid complying with the proposed requirements. The applicability date for newly constructed affect sources is January 8, 2014, while the applicability date for modified and reconstructed affected sources is June 18, 2014.
Commenter 9591 pointed out the close relationship of the standard for new sources to the subsequent guidelines for existing sources. Commenter 9591 pointed out the CAA section 111(d)(1)(A)(ii) requirement that applicability criteria for new source performance standards (NSPS) must be congruent to applicability criteria for existing source performance guidelines (ESPG). This commenter emphasized that section 111(d)(1)(A)(ii) requires the Administrator to prescribe ESPG with applicability provisions that mirror the applicability provisions of the precedent NSPS. The commenter paraphrased the associated criteria as follows (emphasis added): Section 111(d) provides that the Administrator "shall prescribe regulations which establish a procedure ... under which each State shall submit to the Administrator a plan which (A) establishes standards of performance for any existing source for any pollutant ... to which a standard of performance under this section would apply if such existing sources were a new source." Commenter 9591 believed that the underlined portion of section 111(d) requires that the EPA consider the subsequent rulemaking for ESPG when finalizing the proposed NSPS applicability scope because the applicability criteria for the ESPG must mirror the applicability criteria promulgated for the NSPS.
 Commenter (9514) expressed concerns that the proposed applicability exemptions may be problematic in the context of the agency's pending 111(d) rule for existing power plants; since the NSPS are a predicate for regulating existing sources under section 111, the commenter believed that broader coverage under the NSPS will clarify which units will be included under the section 111(d) standards.
The 111(b) applicability in this final rule was set considering practical implementations issues for both 111(b) and 111(d). Specifically, we are not finalizing applicability criteria based on actual operating conditions so that units cannot switch in and out of applicability. We also not that the applicability provisions of 111(b) and 111(d) do not need to be identical so long as all affected existing sources under 111(d) would be affected sources under 111(b) if they were new sources.
Commenter 9514 recommended (with a few exceptions) that whether or not new source standards will apply to a particular unit should be determined based upon the same applicability provisions now in place for criteria pollutants [it was not clear which of the commenter's exceptions were associated with this recommendation].
 Commenter (9514) generally opposed the proposed series of applicability provisions for steam generating units and stated that the agency must retain the current definitions used for applicability under subparts Da, Db and Dc. Additionally, the commenter stated, the EPA should close off loopholes that exist in both the current regulations and proposed rules and apply the standards to all EGUs that supply or were constructed for the purpose of supplying any electricity for sale to the grid. The commenter is opposed to the proposed series of applicability criteria joined by "ands" because, as proposed, the commenter believed these applicability provisions compose significant loopholes. 
 Two commenters (9666 and 10023) supported the exemption of small combustion turbines below 73 MW (250 MMBtu/h).
Commenters (5605, 9406, 9513, 9514, 9771, 9591) generally supported inclusion of the technologies listed in the initial applicability statement of the proposed rule, but recommended that applicability should be more generalized to include "all fossil fuel-fired power plants" because the commenters believed that doing so may simplify development of future frameworks for cost-effective carbon reductions from existing units, such as frameworks based on system-wide approaches. 
Commenter (9406) stated that numerical limitations should apply to all EGUs that supply electricity to the grid, including small EGUs, oil-fired combustion turbines, and simple cycle combustion turbines because excluding some EGUs undercuts efforts to reduce GHG emissions and creates an unbalanced playing field in the market, and because NSPS are technically feasible for the EGUs that EPA proposes to exclude and inclusion will not threaten reliability. 
Commenter 9406 also stated that regulating simple cycle turbines under the section 111(b) rule may help with implementation of forthcoming section 111(d) guidelines for existing EGUs, and the commenter indicated that states participating in the Regional Greenhouse Gas Initiative already regulate CO2 emissions from simple cycle turbines in that market-based allowance program, and the commenter suggested that including all simple cycle turbines in federal regulatory programs may reduce administrative and regulatory burdens implementing federal rules through existing section 110 state programs. Commenter 9406 also recommended that rather than exempting peaking units, at a minimum, simple cycle peaking units, should be subject to work practice standards such as operating safely and with good air pollution control practices, including GHG monitoring and reporting requirements.
Commenter (10025) stated that the rule must apply to all carbon emitting power plants and must be strengthened. The commenter stated that the rule must apply to both future, modified, and existing power plants, placing limits on carbon emissions in line with the trajectory needed to bring atmospheric carbon concentration back to 350 ppm by 2100. 

The final applicability criteria cover some of the source suggested by the commenters, including oil-fired units and simple cycle combustion turbines, but do not include others, such as industrial units and very small (i.e., less than 25 MW) EGUs. For the EPA's complete rationale for covering certain sources by excluding others from the final applicability criteria, see the preamble to the final rule.
 In conjunction with the recommendation for a more generalized initial applicability statement, commenters (9513, 9514, 9771) recommended that the EPA use CAA section 111(b)(2) authority to develop appropriate subcategories of EGUs.
 Commenters 10095 stated that the EPA should use section 111(b)(2) authority to subcategorize steam boilers (by fuel type) and IGCC units. The commenter cited the EPA's response to comments for amendments to Subparts D and Da in 2011 where the EPA held that standards of performance should not be set at levels that preclude the construction of certain affected sources within a category or subcategory. Commenter 10095 goes on to assert that the EPA's failure to subcategorize in the proposal is inconsistent with previous rulemakings, and the commenter believed this failure to subcategorize is arbitrary.
 Commenter (4814) stated that new power plant regulations should be set separately for coal power plants and natural gas generating units. The commenter stated that these emission level standards should be based on best system of emission reductions adequately demonstrated for power plants that are operating commercially in the U.S.
Commenter (9661) stated that a separate and achievable standard for coal-fired electric generating units is necessary. The commenter stated that EPA's proposed NSPS for new coal based units should not require carbon capture and sequestration. The commenter stated that EPA must establish separate standards even if market trends and modeling forecasts suggest that there will be no new coal units built in the foreseeable future. 
Commenter (8024) stated that they agree with EPA's decision to provide separate emission standards for coal and natural gas combined-cycle units. The commenter stated that the agency's previous proposal to combine these two sources into one category (77 RF 22392) failed to recognize the fundamental technical, economic, and engineering differences between these two very different methods of electrical generation. 
Commenter (9649) stated that setting a single standard at the level achieved by NGCC units would have, for all practical purposes, eliminated new coal-fired units as a viable generation option due to the high costs and infeasibility of CCS needed to meet that standard, and would have almost certainly limited any new coal-fired units to geographic areas where CSS could feasibly be used. 

This final rule subcategorizes steam generating units and IGCC units separately from combustion turbines. The EPA has concluded that subcategorization by coal type is not necessary for this final rule. See Sections III.C and IV.A of the preamble for a discussion of the applicability criteria for steam generating units and Section IX.A of the preamble for a discussion of the applicability criteria for combustion turbines.
Commenters (7994, 8918, 8937, 8952, 9001, 9034, 9194, 9407, 9425, 9426, 9428, 9499, 9564, 9592, 9595, 9596, 9597, 9601, 9602, 9665, 9666, 9667, 9678, 9723, 9771, 9767, 9769, 9772, 9780, 10024, 10030, 10048, 10052, 10095,10097, 10098, 10100, 10102, 10238, 10358, 10390, 10393, 10395, 10466, 10500, 10520, 10618, 10788, 10870, 10950, 10952) opposed in part the EPA's proposed selection of technologies to be covered by the standard and provided recommendations for amendments to the proposal. These commenters opposed the general reference to stationary combustion turbines and recommended that the final rule completely exempt simple cycle units from the standard, because future capacity factors for these units may increase above historic levels to support the rapid growth of renewable generating assets and more fundamentally, because simple cycle units serve a different purpose than NGCC units, a purpose that precludes current simple cycle technologies from achieving efficiencies equivalent to NGCC technologies. Commenter 10095 cited extensively from the rational for exempting simple cycle turbines in the preamble to EPA's 2012 proposal, and stated that simple cycle turbines must be treated differently than NGCCs under section 111(b) proceedings. Commenter 9499 stated that SC turbines should not be included in this rule.
Commenters (8952, 8973, 9425, 9426, 9499, 9665, 9666, 9678, 9723, 9780, 10052, 10095, 10098, 10100) also opposed inclusion of simple cycle turbines because these assets typically have the shortest construction schedules and are viable options for filling capacity gaps while lengthy base load transmission and generating projects are permitted and constructed. These commenters believed that the EPA has a reasonable basis (and section 111(b)(2) authority) to explicitly exempt simple cycle (SC) turbines in order to provide system operators with full use of the unique capabilities of SC units to resolve reliability emergencies within minutes while also preserving the capabilities of SC units to replace capacity lost when base load units are recovering from lengthy forced outages. 
Commenters (9426, and 10052) disagreed with the EPA's suggestion that the proposed applicability criteria are necessary to avoid a circumstance where utilities increase use of simple cycle units to avoid the NSPS because the economics of simple-cycle combustion turbines requires their use only on an as-needed basis and it is unlikely that they will be widely-deployed in lieu of combined cycle combustion turbines. These commenters believed a categorical exemption for simple cycle units is necessary to maintain grid reliability. 
Commenters (6870, 7994, 8944, 8952, 9001, 9407, 9428, 9591, 9595, 9596, 9601, 9602, 9654, 9665, 9666, 9667, 9723, 9767, 9769, 9772, 9773, 8911, 9194, 9381, 9426, 9780, 10024, 10030, 10034, 10048, 10086, 10095, 10238, 10239, 10358, 10387, 10390, 10393 10395,10466, 10520, 10606, 10660, 10788, 10870, 10950 and 10052) supported a categorical exemption for simple cycle turbines. 
Commenter (10395) stated that the proposed NSPS can only be met by units having thermal efficiencies associated with natural gas combined cycle (NGCC) EGU CTs. Commenter 10395 stated SC CTs cannot meet the proposed standards. The commenter also stated that since their dispatch to maintain grid reliability may require operation exceeding the 219,000 MWh annual cut-off, SC CTs should be exempt from this rulemaking. Additionally, the commenter stated that the proposed limitation on SC CT annual operating hours presents a bias in favor of industrial sources that do not face similar simple-cycle CT operating restrictions. In summary, the commenter stated that EPA should exclude SC CTs from Subpart KKKK at this time, and wait until the rules are implemented and EPA is able to gather operational data over several years regarding how the new and evolving generation mixes on the grid will work before hamstringing SC CT options. The commenter stated that it makes no sense to include SC CTs under 40 C.F.R. Subpart KKKK, and limit them to only one-third of their capacity. 
Commenter (10052) stated that due to the manner in which utilities utilize simple cycle units, it is unlikely that a categorical exclusion will materially change utility reliance on simple cycle units. The commenter believed that a categorical exclusion is also preferable because it will simply avoid the issue of potentially compromising reliability or decreasing utilities' ability to integrate renewable resources. The commenter stated that if EPA will not exempt simple cycle turbines, they should consider a different standard that is operationally specific to simple cycle turbines.
Commenter (9426) stated that based on EPA's position that meeting the proposed 1,000 lb CO2/MWh standard will not impose any additional costs on new NGCC units, there would be no adverse economic impacts on new NGCC units and therefore no economic incentive to either build simple-cycle turbines instead of NGCC units or to operate new simple-cycle turbines more than would otherwise make economic sense if the EPA were to provide an exclusion. The commenter believed that any claims or concerns that an exclusion for simple-cycle turbines would create an opportunity to evade the standard and could thereby increase GHG emissions are groundless. 
Commenter (9780) believed that excluding new stationary simple-cycle CTs is appropriate because these units provide important grid services that facilitate renewables integration and support reliability. The commenter stated that an exemption will allow maximum operating flexibility for these units to perform these functions. The commenter also stated that the proposed exemption would only apply to GHG performance standards and not to any other emissions limits that may be included in a unit's title V operating permit.
Commenter (9667) stated that exemption for simple cycle units is critical because limiting the exclusion from the Rule to units that supply less than 2919 hours to the grid is insufficient to cover many potential operating scenarios for simple cycle units. 
Commenters (7994, 8952, 9426, 9428, 9665, 9666, 9678, 10052, 10086, 10395, 10466) also opposed inclusion of simple cycle turbines in the initial applicability criteria because many simple cycle turbines cannot achieve the standard, and commenters (8952, 9665) indicated that including simple cycle turbines will benefit other EGU technologies that are not subject to the standard (such as diesel engines) that have higher emissions than simple cycle turbines. Commenter 8952 stated that, theoretically, no commercially available simple cycle gas turbine is able to achieve 1,100 lb/MWh when operating under the real world highly flexible operation demanded of simple cycle turbines. 
Commenter 9678 stated that a specific exemption from these standards would not induce operators to install simple cycle units where NGCC is otherwise economically or practically preferable. Commenter 9678 stated simple cycle turbines and NGCC serve different roles within an electricity market. Commenters 10392, 10876 stated that EPA would be requiring burdensome recordkeeping requirements with no appreciable emission reduction benefits. 
Commenter 9665 stated that simple cycle units should be excluded because their inclusion could adversely affect sales of larger, more efficient simple cycle units. The commenter also stated that if EPA does not exclude simple cycle units, it should revise the rule's applicability requirements and establish simple-cycle specific standards. The commenter also stated that the proposed rule should include language clarifying that the final standards for NGCC do not apply to PSD permits for simple cycle units. 
Commenter 9407 stated that any limitations on SCCT use should be based on need and purpose as represented in operating permits, and not on an NSPS with hard numerical limitations on utilization. 
Commenter 10660 stated that if EPA proceeds to include simple cycle turbines under the NSPS, a separate emission limit would need to be established to satisfy section 111's requirements for a standard that has been demonstrated to be achievable in practice. The commenter stated that EPA's limits do not meet those statutory criteria under anything but the most optimum load and ISO conditions, and, as noted above, simple cycle turbines often function as peaking units and as back-up power units.
Commenter 9666, 10095 noted that EPA has stated that the fuel efficiency of simple cycle turbines is about 29 percent while NGCC units operate at about 48 percent efficiency. 70 Fed. Reg. at 8319. Thus, commenters stated it should be no surprise that simple cycle turbines cannot meet either 1,000 or 1,100 lb CO2/MWh on a 12-operating-month rolling average basis because simple cycle combustion technology is very different than combined cycle technology. Commenter 9666 stated that if simple cycle turbines were to be subject to the proposed NSPS, they could not meet the limit, would be unable to operate, and system reliability would be jeopardized. If EPA wants to subject high capacity factor simple cycle turbines to a GHG NSPS, the commenter stated the EPA should create a separate subcategory, determine an appropriate BSER, analyze emissions from these machines, consider all section 111(b) factors, and propose a limit that is achievable.
Commenter 8952 stated that in the absence of a full exemption for simple cycle gas turbines, the commenter believed the EPA should provide incentives for simple cycle machines to drive to higher efficiencies and reduced levels of CO2 at peak power conditions.
Commenters (8952, 9425, 9426, 9665) believed that the EPA's analysis of historic capacity factors for simple cycle units is inappropriate for determining if simple cycle units will be subject to the standard in the future because these commenters believe that future growth of renewable generation capacity will require proportionate growth in simple cycle capacity because simple cycle technology is the most efficient and reliable technology that can be dispatched in minutes to complement use if intermittent renewable resources. Commenters (9665, 9666) disagreed with the EPA's premise that the proposal will affect an inconsequential number of simple cycle combustion turbines, and commenter 9665 cited an analysis of recent air permits issued in states with progressive renewable portfolio standards (RPS) to support the claim that "far more than one percent of new simple cycle turbines will be affected by the proposed rule." Commenters (8952, 9665) also believed that future turbine packages ordered by system operators may not be dispatched in a manner that allows operation at peak efficiency, but rather that they may be dispatched to maximize how quickly they can follow load and changes in energy supply.
Commenter 9425 stated that in some circumstances, simple cycle turbines are used to support the integration of renewable resources into the grid and may operate more frequently. The commenter noted that simple cycle units that accommodate the increased use of renewable generation should not be penalized by emissions standards that fail to recognize that system emissions are decreasing, even though unit emissions might increase. Commenter (9425, 9780) also stated that if EPA retains the one-third sales test approach as opposed to explicitly exempting simple cycle CTs, it must address a range of compliance issues that weren't addressed in the proposal. Commenter 9425 stated that first, EPA must clarify that the exemption criteria for CTs applies on a per unit basis and not at the facility level. Second, Commenter 9425 stated, as EPA notes, there are implementation issues that arise when a unit that was not built to achieve a standard becomes subject to that standard at some point in the future. 
Commenter 10952 provided a case study provided by Golden Spread Electric Cooperative Inc. that illustrates how and why SCCTs operating as required and unconstrained by operational limits like those proposed can play a vital role in supporting renewable generation and minimizing CO2 emissions. The commenter also provided two detailed scenarios in which SCCTs could be used to support renewables and minimize CO2 emissions. 
Commenter (8957), a preconstruction permitting authority, concurred with the EPA's analysis that the majority of simple-cycle turbines will be excluded based on proposed applicability requirements, and stated that if they are not excluded under the proposed applicability provisions, it is reasonable to apply the proposed standard. 
Commenters (9665, 9771, 10660) opposed the proposed applicability provisions for combustion turbines in conjunction with the proposed emission standards derived from NGCC performance because this combination of applicability and compliance provisions is incompatible with reliability plans in California and other states with progressive Renewable Portfolio Standards (RPS). These commenters presented the generating load profile for a typical day in California with the projected ramp rate needed to accommodate variable contributions from wind and solar assets; the load profile indicated that during the daytime wind and solar power can replace fossil fuels but in the late afternoon and evening the ISO must quickly dispatch fossil fuels to make up for falling solar generation, with a required ramp up of approximately 13,000 MW in just a three or four hour period. Commenter 9665 also provided a quote from a California ISO publication from 2013 that stated, "To ensure reliability under changing grid conditions, the ISO needs resources with ramping flexibility and the ability to start and stop multiple times per day. To ensure supply and demand match at all times, controllable resources will need the flexibility to change output levels and start and stop as dictated by real-time grid conditions." Based on this quote from the California ISO publication, Commenter 9665 asserted that larger, efficient, simple cycle units are the most appropriate way to deal with the significant and rapid power increases required to support use of renewable resources as proven by recent California purchases of aero derivative simple cycle turbines that can achieve full capacity within 10 minutes. These commenters described typical operations (of the simple cycle units that support renewables) as prolonged periods of running at low inefficient loads ready to respond to fluctuating wind or solar conditions followed by several hours at increasing loads as wind and solar decline followed by sustained periods at full load (during periods of calm winds and darkness) to assume the load previously carried by wind and solar assets. These commenters stated that simple cycle units performing this routine duty cycle may be required to operate above applicability thresholds, but that such duty cycles preclude compliance with the proposed standard by simple cycle units.
 Commenter 9771 stated that the size-based standards do not fully acknowledge the changes now occurring in the power sector, which may lead to shifts in how natural gas-fired EGUs are operated. The commenter stated that accordingly, EPA should carefully consider how its standards will interact with a changing power grid to ensure that the standards support this renewable integration, while continuing to set rigorous standards for EGUs that continue to operate in more traditional applications. The commenter strongly urged EPA to consider further subcategorization based on an EGU's operational profile (including, for instance, baseload, conventional load-following, fast-starting/ramping, and peaking) in order to ensure the developed standards support further renewable integration.
Commenter (9771), a permitting authority in a state with rapidly increasing use of renewable resources, stated that emerging demand for flexible resources reflects the increasing importance of generating assets with significantly different emission characteristics compared to historically deployed resources. Commenter 9771 stated that the EPA should recognize these changes and provide regulation in a deliberate and targeted manner for EGUs of all the operating types necessary to support expanded use of renewable resources within a broader strategy for significant reductions from the electricity sector. 
Commenter (8911) stated that the modern role of simple cycle generation can now be safely limited to non-spinning reserve capacity. And even that role applies only rarely when a grid has such a glut of low cost energy that it is not economical for the non-spinning reserve capacity to be supplied by new combined cycle plants. The commenter cited data from California in this portion of their comment. 
Commenter (10390) stated that their experience with the Montana Power Stations demonstrates that SC turbines can be needed and should be allowed to operate without capacity limitations. 
Commenter (9769) stated that the proposed applicability criterion approach for simple cycle combustion turbines does not appear to consider regulating plants using simple cycle technology. The commenter stated that increasing the applicability criterion or the CO2 standard of performance for units with a heat input less than or equal to 850 MMbtu/h would not provide the necessary flexibility and regulatory certainty for new regulatory plants. 
Commenter (10030) stated that EPA recognizes that economics dictate not using SCCTs where CCCTs are otherwise appropriate. The commenter stated that rather than regulating SSCTs based upon unsupported concerns, EPA should defer regulating such units for GHG emissions at this time. 
Commenter (8952) was concerned that the NSPS levels may be misinterpreted and assumed to be BACT for all gas turbines, including large simple cycle projects. The commenter stated such a misinterpretation would effectively ban simple cycle gas turbines. The commenter requested that EPA include specific language to prevent an unintended adverse impact on simple cycle gas turbines. 
Commenter (9514) stated that setting a carbon pollution standard is not only essential for ensuring high efficiency and low emissions from new simple cycle CTs, but could also help ensure that EPA's forthcoming emission guidelines for existing EGUs comprehensively address carbon pollution from the power sector. The commenter stated that the exclusion of peaking units from the NSPS for CO2 pollution from new EGUs could leave uncertainty as to whether such units would be subject to section 111(d) standards. The commenter recommended that instead, EPA should promulgate a three-tiered set of performance standards under which peaking units (i.e., those operating fewer than 1,200 hours annually) - whether CT or CCGT - would be limited to 1,100 lbs CO2/MWh.
Commenter 10119 stated that EPA's proposal to exclude lower capacity and simple cycle gas turbines from the standard is unsupported. The commenter stated that the proposed rule does not adequately explain this exemption. The commenter stated that EPA cannot rely on National Lime Association in support of a decision not to set a standard for simple cycle plants. See Nat'l Lime Ass'n, 627 F.2d at 426 n.28. The commenter felt that EPA has no evidence that all new natural gas plants will be NGCC plants; indeed, the evidence in EPA's possession shows not only that simple-cycle plants will continue to be needed, but also that this part of the power sector is anticipated to grow dramatically. Ultimately, therefore, EPA has failed to provide a rational basis or adequate explanation for its decision not to establish a standard for simple cycle plants. The commenter stated that to the extent EPA intended its applicability standard to exempt simple cycle facilities, its decision comes with significant collateral damage. The applicability standard could also exclude a large number of NGCC plants. 
Commenter 10681 stated that the proposed rule language under part 60, subpart KKKK does not clearly indicate how peaking units would be affected by the proposed rule and requested that the EPA clearly address peaking units in the final rule; the commenter recommended that the EPA establish a definition for peaking unit based on a maximum number of operating hours per year.
Commenter (9515) opposed provisions effectively exempting oil-fired and peaking units, and stated that the EPA did not provide sufficient justification for these exemptions; commenter 9515 recognized the EPA's discretion to create exemptions under section 111, but stated that this discretion is limited by a standard of reasonableness and subject to judicial review. The commenter concluded that the EPA should more fully explain its rationale for exempting oil-fired and peaking units in order to preclude legal actions alleging that these exemptions are arbitrary and capricious.
 Commenter 9515 stated that EPA should more fully explain its exemption for oil-fired units and discuss the costs and benefits of that exemption. EPA should also examine the costs and benefits of regulatory alternatives to exemption, such as establishing a separate, less stringent performance standard for new oil-fired units.
Commenters (9425, 9770, 10024) supported EPA's proposed exemption for combustion turbine units that run exclusively on oil. The commenter stated that the lack of a robust database for new oil-fired units with which to evaluate CO2 emissions does not support the development of an NSPS for oil-fired units. Commenters (9425, 9770, 10024, 10100, 10393) supported exemption of combustion turbine units that run exclusively on oil. Commenter 9425 did not believe there is a robust database for new oil-fired units to support development of an NSPS for oil-fired combustion turbines.
Commenter (9515) stated that EPA should articulate robust justifications for exempting oil-fired and peak-demand units. The commenter stated that EPA's proposed performance standards do not apply to oil-fired generating units or to units that sell less than one-third of their potential electric output to the grid (i.e., peak-demand units). The commenter believed that EPA has discretion to create exemptions when promulgating performance standards under Section 111 of the Clean Air Act, they felt that this discretion is limited by a standard of reasonableness and subject to judicial review. Accordingly, the commenter stated that EPA should more fully explain its rationale for exempting oil-fired and peak-demand units.
Commenter (9515) stated that the EPA should more fully explain why oil-fired units are exempt. The commenter believed that unavailability of natural gas at certain sites does not preclude the EPA from establishing a standard of performance specific to oil-fired units; the commenter believed that the final rule should more fully explain the rationale for oil-fired units with a costs and benefits analysis.
Based on practical implementation concerns (e.g., not having units come in and out of applicability based on actual operating parameters) and interactions with the 111(d) applicability criteria, which include all NGCC units, the final applicability criteria in this final rule include combustion turbines regardless of percentage electric sales (e.g., simple cycle units) and natural gas use (e.g., multi-fuel-fired units). In regards to combustion turbines that burn 100 percent oil because they are not connected to a natural gas pipeline, we expect few new turbines of this type to be built. Any new oil-fired combustion turbines that are built will likely be located in a non-continental area that does not have access to natural gas supplies. As a result, we are finalizing an exclusion for these units and deferring applicability at this time because (1) few new units are expected, (2) we do not have continuous emissions data to establish a meaning output-based standard, and (3) the exclusion of units not connected to a natural gas pipeline will have a minor impact on 111(d) goals. For non-base load units, which include simple cycle turbines, we are finalizing the sliding-scale subcategorization approach and an input-based standard that will provide adequate flexibility to support the growth of new intermittent renewable generation. See Sections IX.A and IX.B of the preamble for a discussion of the broad applicability approach and final subcategories for combustion turbines.
Commenter (9661, 9780, 10520, 10100) stated that EPA should exempt simple cycle mode operations from combined cycle plants in consideration of compliance with the model. The commenter noted that as proposed, the entire combined cycle unit would be subject to the rule and emissions in both simple cycle and combined cycle mode would be included in compliance determinations. Commenter 10100 stated that combined cycle units often operate in simple cycle mode to provide peaking power and to ensure compliance with permit limits applicable to other criteria pollutants. 
 Commenters (9426, 9471, 9592, 9596, 10100, 10500, 10520) recommended that the EPA should also exclude from applicability determinations operating periods when combined cycle units run in simple cycle mode such as during steam turbine maintenance activities. Commenter 9592 stated that there are many operating situations that force combined cycle units to operate in simple cycle mode, and the commenter described a combined cycle unit at his facility with Title V operating permit limits that require the combined cycle unit to switch to simple cycle mode at intermediate loads in order to comply with applicable NOx standards. Commenter 9592 operates a small public power system that serves 80,000 customers, this commenter stated that there are times when combined cycle units must run in simple cycle mode due to malfunctions of steam cycle components, and the commenter indicated that this vulnerability is especially critical for smaller public power systems that do not have a large fleet of units to choose from; in these situations, the commenter asserted, operation in simple cycle mode may be required to meet reliability constraints. Commenter 8023, operator of the largest municipal utility in the U.S., provided similar comments regarding the growing challenges of providing reliable service on smaller transmission and distribution systems when generating units or transmission resources fall off-line unexpectedly. Commenter 8023 also indicated that the primary strategy for mitigating risks of outages on smaller systems is to increase the availability and utilization of fast-ramping, simple cycle gas-fired generators and to operate these flexible assets for sustained periods at partial loads with emission rates significantly higher than the proposed standard. Commenter 9425 stated that the final rule should include provisions for excluding from applicability atypical years of operations when a simple cycle unit is forced to run with a higher than normal capacity factor to ensure grid reliability. Commenter 9471 stated that the Clean Air Act does not require that all EGUs must operate for only base load purposes, and the commenter suggested changes to avoid the implication in the rule that all units must operate at base load conditions where they are most efficient: (1) the EPA should revise the final rule to allow NGCC units the use an 84-month averaging period without the associated requirement for CCS; this change would help mitigate the unavoidable higher emissions during startups and shutdowns; the commenter also recommended increasing the proposed standards. 

 The EPA disagrees with the commenter that simple cycle operation for a NGCC unit should not be counted towards compliance demonstration calculations. The final rule does not set separate standards for simple cycle and NGCC units. Instead, the final rule sets separate standards for base load and non-base load units and distinguishes these subcategories based on the amount of electricity sold to the grid, derived from a unit's nameplate design efficiency calculated as a percentage of potential electric output. The final base load unit emission standard includes sufficient compliance margin to allow flexibility of NGCC operation, including running in simple cycle mode.  If a NGCC unit operates for significant periods in simple cycle mode, it will likely be subject to the non-base load unit emission standard. The non-base load standard requires the use of clean fuels, and efficiency does not factor into compliance with the emission standard.
Commenter (9426, 9591, 9769) requested that EPA consider exempting ancillary services or regulation service from the final rule. The commenter stated that such an exemption would provide regulatory certainty for new units similar to DGGS, designed to support system reliability and further facilitate the integration of renewable resources.
The final rule does not exempt ancillary services. Such an exemption is unnecessary because the sliding-scale approach and system emergency exemption provide adequate flexibility for non-base load units to support the integration of renewables. 
Commenter 9514 stated that the EPA should ensure that fast-start combined cycle units are subject to the standard. 
 Commenter (9514) stated that EPA should also ensure that fast-start CCGTs are covered under the proposed NSPS. Commenter 9769 added that a particular class of fast-start generators referred to as "ancillary services" or "regulation services" should be expressly exempted because these units are required by reliability regulations and are integral to system reliability when integrating renewable resources. The commenter provided a definition for these types of units from a FERC Open Access Transmission Tariff. 
The final applicability criteria in this final rule do not distinguish between the design characteristics of stationary combustion turbines. Instead, the non-base load and base load subcategories are determined strictly on the percentage of electric sales. Fast-start NGCC units are covered by the final rule, and will be subject to an input-based standard if they are below the percentage electric sales threshold or an output-based standard if they are above the threshold. Fast-start NGCC units can meet either standard depending on how they are operated. The final rule also excludes electricity generated as a result of a system emergency from counting toward the percentage electric sales threshold. The EPA has concluded that this exclusion will provide adequate assurance that the final requirements will not result in reliability concerns.
Commenter 9780 stated that EPA must affirm that the reactivation of mothballed units would not subject such units to the CAA section 111(b) standards for new units. The commenter stated that depending on circumstances regarding reliability needs and market economics, there is a possibility that companies may reactivate units that have been essentially "mothballed" or placed into cold storage. The commenter stated that reactivation of a dormant facility is not considered to be construction of a new source for section 111(b) purposes. The commenter stated that the EPA needs to clarify that if an EGU is not modified or reconstructed before restarting, the project does not trigger section 111(b), as long as the federal and state operating permits remain effective. 
Applicability determinations are made on a case-by-case basis, so whether a reactivated mothballed unit could be considered subject to this NSPS will depend on a variety of factors, including how long the unit has been mothballed and whether the unit is engaging in upgrades that could be considered a modification or reconstruction.
Commenter 9406 stated that one exception to the preceding recommendation to establish numerical CO2 emission standards for simple cycle turbines is necessary: simple cycle units that trigger NSPS applicability when transferred from one facility to another facility; in those cases, the older unit may not be as efficient as a new unit, and the EPA should establish work practice standards rather than numerical emissions standards for such relocated units. 
While applicability determinations are made on a case-by-case basis, moving an existing combustion turbine to a new location would generally not trigger the 111(b) requirements.
Commenters (10022, 10504) requested that the EPA exempt electric utilities operating in Alaska from applicability under the proposed rule. Commenter 10022 explained that the proposed rule would further increase the cost of electricity in Alaska where costs are already one of the highest in the nation (18.33 cents/kWh in 2013). The commenter stated that natural gas is not readily available in Alaska and is not cost effective for all parts of Alaska. The commenter believed that unavailability of natural gas to interior Alaska and remote communities rebuts the EPA's justification for the proposed standard "based on the fact that inexpensive natural gas is readily available in the U.S. for power generation." The commenter stated that this generalization is not true for Alaska. The commenter described Alaska's reliance on coal-fired steam units as well as oil-fired combined cycle and oil-fired simple cycle turbines and stated that the cost of oil-fired generation continues to increase, placing financial stress on interior Alaska communities. The commenter also stated that owners of the refinery that provides the majority of the oil used for generation have announced closure of the refinery, leaving coal as the only viable fuel available for meeting the demand for electricity in interior Alaska. The commenter went on to describe how many of the generalizations used by the EPA to justify the proposed standard are not true for interior Alaska and the commenter added that requiring new coal-fired EGUs in Alaska to install and operate partial carbon capture and sequestration (CCS) has eliminated interior Alaska's most affordable power source. The commenter stated that the sale of captured CO2 for Enhanced Oil Recovery (EOR) is not viable for interior Alaska's coal-fired plants due to the lack of nearby oil or gas production activities. The commenter also provided a discussion of how providing an exemption from the proposed rule for Alaska could improve interior Alaska's air quality which is adversely impacted by winter inversions and wood-burning for home heating. The commenter also described how unique considerations are necessary for Alaska's electric system compared to the contiguous 48 states: Alaska is extremely remote, challenged with severe winter weather conditions, and constrained by limited infrastructure and support services. The commenter asserted that basic community services taken for granted elsewhere in the US are simply not available in most areas of Alaska. Utility operators have unparalleled challenges with transportation, logistics, staffing, equipment availability, and short construction seasons. The commenter also stated that Alaska's isolated electric grid systems are not in the same category as interconnected contiguous US electric systems, and access to fuel resources is limited and varies from location to location. The commenter believed that the GHG NSPS discriminates against communities that do not have access to natural gas because in those communities, businesses will not be able to afford to operate, families will be displaced, and community's financial health will deteriorate. Finally, the commenter asserted that impacting the reliability of Alaska's electric utility sector puts the safety of all Alaskans at risk because the most important job of Alaska electric utilities is to provide reliable electric service to our communities through the extreme cold, lengthy and dark winter months when reliable electric service is critical for life and safety. The commenter stated that unlike interconnected utilities in the contiguous US, Alaska's utilities do not have the option of relying on an integrated grid system for backup support.
Commenter (10672), an electric utility operator in a non-continental, island territory, requested that the exemption for non-continental electric utility units be reintroduced into the final rule because the commenter believed that only a clear exemption for these islands will be sufficient to allow construction of new power plants since the only fuel available on such islands is oil and there are no opportunities for carbon sequestration.
 Commenter 9194 commented that the Florida Keys should be included in the proposed rule's definition of "non-Continental areas" of the U.S. and thereby excluded from the proposed new source standard, since pipeline-quality natural gas is not available in the Florida Keys and there are no plans to build a natural gas pipeline in this environmentally sensitive area. 
Combustion turbines without access to natural gas will not be subject to the requirements in this final rule. The achievability of the final requirements for coal-fired EGUs is discussed elsewhere in this RTC. 
Commenter (10100) also supported applying the standard to only CO2 emission from affected sources. 
 See Section III.G of the preamble for a discussion of which GHGs are covered in the final rule.
Commenter (10100) urged the EPA to also exclude coal refuse-fired units because, the commenter asserted, EGUs that burn over 75 percent coal refuse on an annual basis have no net GHG emissions in the long term since unused coal refuse piles are constantly burning due to their size and exposure to atmospheric oxygen.
 Commenter (10100) urged EPA to exempt coal refuse-fired EGUs from the NSPS. The commenter stated that in the alternative, the commenter supported EPA's proposal to establish a subcategory for coal refuse-fired EGUs. The commenter cited 79 Fed. Reg. at 1496. 
 The EPA is not finalizing an exemption for coal refuse-fired EGUs. The EPA notes that the industrial CHP exemption has been expanded, however, and new coal refuse-fired units are generally small enough that they could be designed as an industrial CHP unit. See Section III.E of the preamble for a discussion of the coal refuse issue.
Commenter (9514) opposed the "50 percent solid-derived fuel" applicability threshold for IGCC units because, the commenter believed, this proposed definition would allow an IGCC to obtain up to 50 percent of its heat input from coal without having to meet the emission limit reflecting the use of partial CCS, while a pulverized coal plant that combusts 10 percent or more coal, would be covered by the partial CCS standard. Commenter 9514 also opposed the "50 percent solid-derived fuel" applicability threshold for IGCC units in conjunction with the 90 percent threshold for natural gas usage in combustion turbines because, the commenter believed, a CCGT that burned less than 50 percent syngas and 90 percent or less natural gas would escape regulation altogether, since it would qualify as neither an IGCC nor as a natural gas-fired CCGT. The commenter asserted that these exemptions would encompass plants whose fuel mix consisted of 45 percent syngas and 55 percent natural gas, or 85 percent natural gas and 15 percent oil. Commenter 9514 also expressed concerns that the proposed 90 percent applicability threshold for use of natural gas in combustion turbines would not cover any CT that burned 90 percent or less natural gas regardless of its heat input from syngas. The commenter believed that IGCCs should be required to operate on an even footing with other steam EGUs that combust coal, and be subject to the same 10 percent test as other coal-fired plants; the commenter subsequently provided draft applicability provisions (for the EPA's consideration) to close these perceived applicability gaps.
 Commenter 10030 stated that EPA should withdraw the Proposal relative to solid fuel fired units. Commenter 10030 stated regulation of GHG emissions from EGU's firing coal, petroleum coke, or biomass should be predicated upon their efficiency, as has been proposed for and addressed in BACT determinations for other sources.
The applicability criteria in the final rule will continue to cover IGCC units that burn less than 50 percent syngas. The IGCC unit will switch to either the multi-fuel-fired combustion turbine subcategory (if burning 90 percent natural gas or less) or the base load natural gas-fired combustion turbine subcategory (if burning more than 90 percent natural gas) during these periods.
Commenter (8973) believed that all units 25 MW and below, regardless of level of electricity supplied to the grid or fuel type, should be exempted to provide greater flexibility for entities needing to install new units for peaking purposes as well as those units generally needed in response to emergency conditions.
Commenter (9773) believed that the proposed standard should not apply to the following source categories: (1) types of generation that were not evaluated in setting the NSPS standard, including solid fossil fuel units smaller than 550 MW and developing technologies; (2) simple cycle combustion turbines; and (3) efficient combined heat and power (CHP) plants. 
 The applicability of this final rule does not cover units that are only capable of selling 25 MW or less or industrial CHP units. However, the EPA has concluded that it is appropriate to cover units greater than 25 MW and simple cycle combustion turbines. 
Commenter (9198) stated that EPA should clarify that all units subject to CAA section 129 solid waste combustion standards are exempt from the proposed GHG NSPS. The commenter noted that the Agency specifically cites in proposed Section 60.5509 that facilities that are municipal waste combustors (MWCs) subject to subpart Eb (large MWCs) are not subject to the proposed GHG NSPS, but it does not clarify that other MWCs subject to Section 129 are also exempt. The commenter stated that this exemption should include the small MWCs subject to Subpart AAAA. As EPA finalizes the rule, the commenter urged the Agency to retain this important Section 129 solid waste combustion exemption for MWCs both large and small. 
See Section III.D.3 of the preamble for a discussion of municipal waste combustors.
Commenter (9665) stated that the EPA should exempt the combustion of waste fuels, such as blast furnace gas and refinery fuel gas, to ensure that the rule does not reduce incentives for the use of these byproducts.
 While these fuels are covered under the final rule as part of the multi-fuel-fired subcategory for combustion turbines, the requirements are minimal and will not discourage the use of these fuels.
Commenters (9736, 8969, 8964, 8970, 9318, 9671, 9672, 10392) cited the AMP/OMEA list of recommended exclusions for this rule, which included:  All units 25 MW and below - regardless of level of electricity supplied to the grid or fuel type; All units supplying less than one-third (or 40% capacity factor, if EPA chooses to raise the threshold) of their potential electric output to the grid regardless of size or fuel type; Reciprocating internal combustion engines (RICE units) (EPA recommended excluding these sources); Non-natural gas stationary combustion turbines (CTs) (EPA recommended excluding these sources); Existing sources undertaking modifications or reconstructions (EPA recommended excluding these sources, which will be subject of a separate rulemaking); Certain projects currently under development (EPA recommended excluding these sources).
Commenter (9773) stated that simple cycle, solid waste fossil fuel generation smaller than 550 MW, biomass, and CHP plants should be exempt from this ruling. 

This final rule does not cover units that are not capable of selling over 25 MW-n to the grid, stationary combustion turbines not capable of firing natural gas, reciprocating engines, modified combustion turbines, and certain modified steam generating units and IGCC units. The industrial CHP exemption has also been expanded since proposal. However, we are finalizing a modified version of the broad applicability approach we solicited comment on. Non-base load and multi-fuel combustion turbines will be required to comply with an emission standard based on the use of clean fuels. The rationale for adopting the broad applicability approach and the corresponding clean fuels standards is discussed in the preamble to this final rule.
Commenter (9591) stated that there has been a large increase in demand for diesel-fired reciprocating internal combustion engines, and decrease in coal-fired generation as a result of the decreased price of natural gas. The commenter recommended that as the share of smaller sources of generation increases in the electric market, these sources should be regulated under the proposed rule in order to preserve a level playing field.
 Commenter 9665 stated that reciprocating internal combustion engines (RICE) can use a wide variety of fuels to generate power, can range in size from 120kW to 20 MW, and can be grouped to deliver a wide range of outputs to the grid. Commenter 9665 stated that in 2013, a utility in Oregon announced development of a 220 MW power plant composed of twelve 18 MW or larger RICE. Commenter 9665 opposed including simple cycle units in the GHG standard because modular RICE plants used for power generation are not included in the standard, and since modular RICE plants (like simple cycle turbines) have the capability of supporting the use of renewable resources for power generation, they compete directly in markets with expanding renewables. Commenter 9665 believed that applying the GHG standard to simple cycle turbines will act as an incentive for utility companies to select RICE technologies because RICE will not be subject to the CO2 limits or capacity factor constraints proposed for combustion turbines. Commenter 9665 also believed that including simple cycle turbines while omitting RICE could lead to overall emissions increases due to the higher carbon fuels typically used in RICE. 
 Commenter 9665 stated that including simple cycle gas turbines without imposing limitations on reciprocating engines would create incentives to install the excluded units and potentially lead to higher CO2 emissions when such units burn other fuels. 
The sliding-scale approach and final emission standard for non-base load units ensure that new simple cycle units will not be subject to burdensome requirements that restrict their historical use or potential future use backing up intermittent renewables. Therefore, the final rule will not provide a regulatory incentive to for owners and operators to move away from simple cycle combustion turbines toward other technologies not subject to the final rule.
Commenter (5605, 6564, 8952) responded to the EPA's request for input on the use of the new source review program is the appropriate mechanism for establishing site specific greenhouse gas requirements and whether the EPA should exempt stationary combustion turbines at compressed air energy storage (CAES) facilities; the commenter concluded that use of the NSR program could be appropriate, and expects construction of only a limited number of new CAES facilities; the commenter added that at these plants, all combustion turbines should be considered for NSR permit limits with no exemptions so that the entire energy generating system should be subject to an aggregate limitation on carbon dioxide emissions.
Commenter (10554) supported exemption of CAES facilities for three reasons: the proposed one-third electric sales of potential electric applicability requirement may not exempt all CAES facilities; the emissions from a CAES plant will be about one-third of those from a similarly sized combustion turbine (CT) plant on a per MWH basis and any emissions resulting from the electricity used to compress the air would already be accounted for by the facilities that generated that electricity, and it would be redundant to account for those emissions again in the output of the CAES plant; and finally, a CAES plant is expected to provide enhancements to the grid and allow successful integration of significant amounts of renewable resources while providing grid stability during intermittent operations.
Commenter (4711) a developer of CAES technologies supported exemption of stationary turbines at CAES facilities for two reasons: the CO2 emissions associated with CAES turbine operation are well below the proposed standard and the number of CAES facilities likely to be built represents a small fraction of the generation expected to be brought into service due to the cost and scarcity of suitable underground storage media. The commenter added that at this point in the evolution of CAES technology, the commenter believed a strong argument can be made for exemption, but if the EPA decides to apply the proposed standard to CAES facilities, the commenter strongly urges the EPA to refrain from any effort to quantify the CO2 implications of compression energy.
The final rule does not include a specific exemption for CAES units. These units will be subject to the non-base load unit requirements included in this final rule, which present minimal additional burden.
 Regarding the proposed applicability provisions that limit applicability of the GHG emissions standards to newly constructed EGU technologies meeting the proposed definitions of steam generating units, IGCC, and stationary combustion turbines, Commenters (9592, 9597, 9678, 10100, 10952) supported the preamble language excluding from the proposal existing sources undertaking modification or reconstruction because the commenters believe the preamble language is consistent with the definition of "new source" in CAA section 111, and the commenters expressed agreement with the EPA's conclusion that if an existing source undertakes a modification or a reconstruction, it would not be treated as a "new source" subject to the proposed standard; some commenters (10100, 10952) requested that the EPA include an explicit exclusion for modified and reconstructed existing sources in the final rule. Another commenter (10243) requested that the EPA provide guidance that the proposed standard does not apply to modified or reconstructed units; this commenter also requested that the guidance delineate the portions of the affected facility that are subject to the standard and that the guidance reaffirm the pollution control project exemption in the general provisions of Part 60 and other guidance not directly related to the proposed rule language.
 Commenter (9780) stated that EPA must clarify that the "affected facility" for purposes of an EGU CAA 111 modification is limited to the "steam generating unit" boiler island. The commenter stated that EPA's regulations and past guidance contain detailed rules as to when a physical or operational change at an existing source is a modification that triggers section 111(b). The commenter noted that in the case of section 111(b) standards applicable to fossil fuel-based EGUs, EPA has historically interpreted the "affected facility" to include only the "steam generating unit" boiler island, and not the components of the generating facility. The commenter stated that this means that installation of pollution control equipment falling outside the boundaries of the boiler island would not be a change to the "affected facility" and therefore cannot trigger regulation of that unit as a modified source under CAA section 111(b). Accordingly, stated the commenter, EPA should issue guidance that confirms that the installation of SO2 scrubbers, fabric filters and other add-on emissions control equipment does not entail either a physical or operational change to the boiler island.
Commenter (9665) stated that the EPA should include rule language that clearly shows subpart Da sources are not subject to NSPS modification requirements. The commenter pointed out that the proposed rule language makes it clear that modification and reconstruction requirements are not applicable for the proposed CO2 emissions standards in subparts KKKK and TTTT. However, commenters (9665, 10952) stated, the proposed regulatory text for revised Subpart Da does not include similar language, and the commenter recommended adding consistent exclusionary language to subpart Da.
 Commenter 9780 stated that EPA should provide regulatory certainty by expressly excluding modified EGUs from applicability in the Regulatory Language. The commenter included specific changes they would make to the regulatory language:
1. Proposed Amendments to the Proposed Regulatory Language for Subpart Da 'Standards of Performance for Electric Utility Steam Generating Units.'
60.46Da Standards for carbon dioxide (CO2).
(b) The following EGUs are not subject to this section:
***
(4) Existing EGUs, including existing EGUs that are modified or reconstructed.
2. Proposed Amendments to the Proposed Regulatory Language of Subpart KKKK 'Standards of Performance for Stationary Combustion Turbines.'
60.4305 Does this subpart apply to my stationary combustion turbine?
(c) For purposes of regulation of greenhouse gases, the applicable provisions of this subpart:
(1) affect your stationary combustion turbine if it meets the applicability conditions in subparagraphs (c)(5)(v) of this subsection.
(1)(I) Commenced construction after [DATE OF PUBLICATION IN THE FEDERAL REGISTER];
(2)(ii) Has a design heat input to the turbine engine greeter than 73 MW (250 MMBtu/h);
(3)(iii) Combusts fossil fuel for more than 10.0 percent of the heat input during any consecutive years.
(4)(iv) Combusts over 90% natural gas on a heat input basis on a 3 year rolling average basis; and 
(5)(v) Was constructed for the purpose of supplying, and supplies, one third or more of its potential electric output and more than 219,000 MWh net electrical output to a utility distribution system on a 3 year rolling average basis.
(2) do not affect your stationary combustion turbine if it is an existing stationary combustion turbine, including if it is existing, modified or reconstructed.
3. Proposed Amendments to the Proposed Regulatory Language for Subpart TTTT 'Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units.'
60.5509 Am I subject to this subpart?"
(b) You are not subject to the requirements of this subpart if your affected facility meets any one of the conditions specified in paragraphs (b)(1) through (b)(56) of this section.
***
(6) Your affected facility is an existing EGU, including an existing EGU that has been modified or reconstructed.
In June 2014, the EPA proposed standards for modified and reconstructed units. The EPA is finalizing standards for reconstructed steam generating units and combustion turbines. The EPA is also finalizing standards for modified steam generating units that increase hourly CO2 emissions by more than 10 percent. The EPA is withdrawing its proposed standards for modified steam generating units that increase hourly CO2 emissions by 10 percent or less, as well as the standards for modified combustion turbines. The EPA explains all of these decisions in the preamble to the final rule. The EPA notes that the pollution control project (PCP) exemption, which was not reopened as part of this final rule, exempts additions of pollution control equipment from being considered a modification.
Commenter (10098) stated that the EPA must clarify that the proposed standard applies to individual EGUs and not to facilities because the commenter believed that making the rule applicable at a facility level would affect existing facilities adding new capacity.
 While recommending an explicit exemption for simple cycle units, commenter 9425 requested that the EPA clarify that applicability criteria for combustion turbines applies on a per unit basis and not on a facility-wide basis.
 NSPS applicability is determined based on the definition of affected facility in each subpart. While the term affected facility is used for NSPS purposes, it generally refers to individual emission units. In this case, an affected facility refers to an individual EGU, not the entire facility.
Commenter 8743 stated that the EPA must exclude the Mesaba Energy Project from applicability under the proposed rule. The commenter described this project as a 1200 megawatt integrated gasification combined-cycle ("IGCC") power plant to be located in Northeastern Minnesota. The commenter stated that the Project was selected by the U.S. Department of Energy ("DOE") in its competitive Clean Coal Power Initiative ("CCPI") Round II solicitation to receive federal funding. The commenter said that the EPA must exempt the project because of the significant work that the commenter has undertaken to preserve the validity of required permits for both NGCC and IGCC plans. Commenter 8743 stated that the EPA had drawn an errant conclusion in the technical support document related to the EPA's assertion that the developer of the Mesaba Energy Project had relinquished the right to have its comments taken seriously because the developer thereafter sought to permit the project's power block apart from its gasification equipment. The commenter believed that it is not in the interest of Minnesota or federal taxpayers to waste the significant efforts and funding expended to date on the project. The commenter respectfully requested that EPA make certain changes to the rule to ensure the Mesaba Energy Project can comply with the proposed standard or be exempted; alternatively the commenter suggested that the EPA should provide a mechanism in the Rule or institute some other relief to reimburse stakeholders for their investments and support the completion of permitting of the power block portion of the project to be fired by natural gas so that the project can comply with the proposed rule. 
 Commenters 10953, 11503, and 11221 provided comments on the proposed rule's treatment of Plant Washington, a proposed 850 megawatt (MW) coal-fired power plant that would be located in Washington County, Georgia. The commenter stated that Plant Washington has not commenced construction and does not qualify as an existing source exempt from the proposed new standards. The commenter also stated that Plant Washington is not on the verge of commencing construction because the project developer is currently seeking an extension of the construction deadline under the project's Prevention of Significant Deterioration (PSD) preconstruction permit. The commenter went on to state that this project is "stalled" with no significant financing, no customers to buy the expensive power it would generate, and no real prospect of moving forward in the near future. The commenter provided additional legal arguments for why this particular project should not be treated as having "commenced construction" under the general provisions of Part 60.
Commenter 10953, 11053 urged the EPA to fully regulate Georgia's Plant Washington under the new NSPS for GHGs. The commenter stated that the draft rule suggested that Plant Washington may be designed to offer fuel diversity to a group of customers that are willing to pay a premium in electricity prices. The commenter lives in Georgia and stated that they have no desire to pay a premium and add more coal-fired power to their coal-heavy energy mix. 
Commenter 10030 stated that they understand that EPA's proposal would not apply to the Wolverine Clean Energy Venture (WCEV), but that the WCEV's status relative to a final GHG NSPS for new EGU's could change if the commenter does not actually commence construction of the project prior to the finalization of an applicable NSPS emission standard for CO2. The commenter stated that all the Proposal does is "propose" that the WCEV not be subject to the Proposal's standards if construction commences before a final rule. Uncertainty remains as to whether the WCEV will be subject to a standard under Section 111(a) or Section 111(d) and what that standard may be.
See Section III.J of the preamble for a discussion of certain projects under development. The EPA is not making final applicability determinations for these sources in the final rule.
Prospective Applicability Criterion - Intended Purpose
Commenter 9514 supported retaining the current heat input capacity under 40 CFR Part 60 Subpart Da as applicability criteria for the new GHG standard for steam generating units so all parties can determine prior to construction whether the NSPS applies. 
Commenters (9514, 10100) noted that the proposed revisions to Subpart Da were inconsistent with the alternative revisions under Subpart KKKK and Subpart TTTT because the proposed revisions under Subpart Da omitted the criteria specific to the prospective design purpose of a new EGU. 
Commenter 9514 opposed use of prospective criteria related to the intended purpose of a new EGU because the commenter is concerned that unexpected business conditions in the future may make it more profitable for the operator of an industrial unit to sell electricity to the grid rather than support the intended industrial activity; commenter 9514 also provided anecdotal evidence of industrial sources selling significant quantities of power to the grid during periods of low prices for their industrial product. 
Commenter 9514 also expressed concerns that operators might misrepresent the future-intended-purpose of a new unit to avoid applicability. Commenter 8957 opposed the prospective applicability criteria and believed applicability should be based on a source's actual operations rather than the source's purpose at the time of construction.
Commenter 9514 also opposed the use of prospective applicability criteria because an interested member of the public must demonstrate an ongoing violation in order to bring a citizen suit, and a prospective obligation cannot be determined with certainty; therefore, the commenter believed, the prospective criteria included in the EPA's proposed regulations undermine citizen enforcement, a critical component of the Clean Air Act.
Commenter 10098 supported use of the prospective purpose criteria because the commenter believed this criterion avoids uncertainty at the time of construction. 
Commenter 9771 supported the general idea of a prospective applicability determination and recommended that EPA require applicants to determine which operational category they will be subject to, including corresponding emissions limits, at the initial application stage of permitting, followed by ongoing verification, because this approach is consistent with many federally approved SIPs.
Commenter 9427 asked, who determines, and when do they determine whether or not the "purpose" of the turbine is to supply more than one-third of its potential electric output to the utility distribution system? This commenter also asked what criteria should be used for this prospective determination. Commenter 9427 recommended that the "purpose" criteria in proposed section 60.4305(c)(5) should be removed as subjective and unenforceable as a practical matter.
 The EPA agrees that prospective applicability criteria and determining "intent" of a project is not an ideal approach. Therefore, the applicability in this final rule replaces the prospective intent applicability criteria with federally enforceable permit restrictions. This approach eliminates the subjective nature of determining "intent" and makes applicability criteria clear for the regulated community, permitting authorities, and the public.
Retrospective Applicability Criteria - General
Commenters (8957, 9427) generally supported the use of retrospective applicability determinations but opposed using a different applicability period for combustion turbines compared to boilers, and the commenter believed the applicability test should be three years for both boilers and turbines. Commenter 8957 recommended including requirements that require operators to use their business projections to evaluate whether or not they will be subject to the standard at the end of the three year period; sources projecting operations above applicability thresholds should be required to maintain all records and submit all reports required by the rule on an annual basis; source projecting non-applicability should be required to maintain records verifying applicability status. Commenter 8957 stated that a compliance report should not be required for non-affected sources, but verification records should be maintained for five years and available to EPA or the permitting authority upon request. 
Commenter 9426, a regional electric utility, stated that they do not foresee any implementation issues for either steam generating units or combustion turbines associated with proposed applicability requirements based on operations after construction; however this commenter simultaneously reiterated previous recommendations for an explicit exclusion for simple cycle turbines.
Commenter 9733 supported the proposed retrospective applicability criteria adding "and supplies" to "constructed for the purpose of supplying" because these changes make the exemption for CHP units comparable to the exemption for cogeneration units in the Acid Rain program.
Commenter 9733 supported the proposed revisions to Subpart Da applicability related to adding the phrase "and supplies" to "constructed for the purpose of supplying" because this provision makes determination of NSPS applicability an ongoing process rather than one based solely on predictions prior to construction. This commenter also supported the proposed annualization of the 25 MW capacity requirement to 219,000 MWh per year because the commenter believed these revisions will make the proposed exemption for CHP units comparable to the exemption for cogeneration units in the Acid Rain program. Commenter 9733 also supported the additional flexibility provided by the proposed one-third sales criterion. 
Commenter 9427 supported the use of retrospective operating data as applicability criteria but was confused by the averaging period.  
 Commenters (5537, 8952, 9513, 9514, 9771,10095, 10098) opposed the proposed retrospective applicability criteria related to actual output supplied during a preceding compliance period because, chronologically, such criteria do not allow the permitting authority and the public to know in advance whether or not the GHG standard applies to a proposed new unit. In the proposed applicability criteria language, "was constructed for the purpose of supplying, and supplies", commenter (9514) recommended that the conjunction preceding the retrospective criteria be revised from "and" to "or" because the commenter believed this logic is consistent with current rules implementing the Acid Rain program and is consistent with the EPA's "once in, always in" doctrine.
 Commenters (2984, 7994, 8918, 8952, 9382, 9407, 9425, 9426, 9499, 9665, 9667, 9678, 9774, 9780, 10048 10098, 10100, 10240, 10392, 10518, 10660, 10876, 10952) stated that EPA should exclude simple cycle turbines from the one-third sales criteria. Commenter 10098 stated that EPA's inclusion of simple cycle turbines is arbitrary, capricious, and unlawful. Commenter 10098 also stated that the very notion that owner and operators would be subject to an operation-based applicability test is absurd under the NSPS, which was designed to provide clear and predictable standards of performance for new sources that would apply when they begin operations.
Commenter 9514 opposed the use of these retrospective applicability criteria because an interested member of the public must demonstrate an ongoing violation in order to bring a citizen suit; midway through the proposed 3-year applicability period, the source's obligations under the standard cannot be determined with certainty; therefore, the commenter believed, the retrospective, 3-year criteria proposed undermines citizen enforcement under the Act.
Commenter 9513 opposed the proposed use of retrospective applicability criteria because applicability could change from month to month and the commenter believed these changes in applicability determinations would create implementation problems for compliance and enforcement. Additionally, commenter 9513 expressed concerns that permitting authorities would not know for 3 years whether a source met the NSPs applicability criteria, and authorities would not have a proper basis for considering NSPS sources when establishing BACT floors.
Commenters (5537, 9771), pre-construction permitting authorities, opposed any retrospective applicability approach to be completed for a new source after issuance of the construction permit because the commenters believed this approach would result in compliance issues and in difficulties in determining proper pre-construction and operating permit conditions. 
Commenters (9514, 9666) opposed the aspect of the criteria that differentiates EGUs that sale output to the grid versus EGUs owned by industrial sources for onsite consumption of electricity. Commenter 9514 opposed this aspect because the commenter believed that such criteria would allow a consortium of companies to form for the purpose of purchasing electricity directly from new coal-fired plants (i.e., bypassing the grid); the commenter believed that such an arrangement would allow the associated new the coal-fired plants supporting the industrial consortium to avoid applicability based on the proposed language. 
Commenter 10098 believed that if retrospective applicability criteria are finalized, simple cycle operators could face an untenable position: if unanticipated peaking power is required in a certain area, operators would face the choice of shutting down the plants, potentially resulting in brown outs, violations of contractual power supply agreements, and violations of North American Electric Reliability Corporation and ISO guidelines, or continue operating and be subject to three years of NSPS violations. 
Commenter 10098 believed that an applicability test that concludes after construction and operation have commenced is inconsistent with the general purpose of an applicability test: which is intended to provide clear and predictable standards of performance for new sources that would apply when they begin operations. 
Commenter 8952 opposed the retrospective 219,000 MWh criteria because this commenter believed it will allow smaller units to operate for additional hours, above the one-third sales capacity threshold while restricting operation of more efficient larger turbines
Commenter 9771 recommended that EPA require applicants to determine which operational category they will be subject to, including corresponding emissions limits, at the initial application stage of permitting, followed by ongoing verification, because this approach is consistent with many federally approved SIPs. 
 Commenter 5537 stated that in addition to the typical NSPS applicability criteria (i.e., a source must be greater than 250 million Btu per hour (mmBtu/hr) heat input), EPA is also proposing to include applicability provisions akin to the Title IV Acid Rain applicability provisions. Commenter 5537 stated these additional applicability criteria would apply for new fossil fuel-fired electric utility steam generating units, integrated gasification/combined cycle (IGCC) sources, and natural gas-fired stationary combustion turbines for the purpose of regulating CO2 emissions from these sources. 
 Commenter 9514 stated that EPA should abandon its proposal to re-define EGUs so as to exclude any unit from regulation unless it is designed to supply, and actually supplies, more than one-third of its potential electric output capacity and 219,000 MWh annually to the grid. The commenter stated that instead, it should continue to provide specific calculation procedures for emissions from regulated cogenerating facilities, and should apply the standards to all EGUs that supply or were constructed for the purpose of supplying any electricity for sale to the grid.
Commenter 9514 stated that under EPA's proposal, a source would no longer be subject to the NSPS if it fell below the threshold for any of the applicability metrics that are calculated on a .......(or, in some cases, annual) basis. The commenter felt that this would create a situation in which no one would know whether a particular plant will be subject to the standards at all until years after the emissions had already occurred. Furthermore, because a number of the proposed applicability provisions apply on a rolling basis, the commenter stated plants operating near the threshold could move in and out of the regulatory system from one month to the next. the commenter stated not only would this create significant practical problems for compliance and enforcement purposes, it would add unnecessary complication to Title V and PSD permitting as well, since authorities would not know whether certain sources would or would not be subject to the NSPS until well after those plants had been operating for several years, and would not have a proper basis to establish a BACT floor for those units. The commenter noted that EPA has suggested that sources need flexibility in their operations. The commenter agreed that there may be areas, such as those addressed in EPA's tailoring rule, where CO2 emissions are treated differently than SO2 or NOx, but EPA has not attempted to demonstrate a reason for such a difference in these provisions.
 Commenter 9514 stated that the definition of co-generating sources would pose a much larger problem by (1) creating a situation in which source operators, permitting and enforcement authorities, and the public will not know whether a source is in compliance until the end of the averaging period.
The EPA agrees that retrospective applicability criteria based on actual operating conditions are not ideal. The final applicability criteria do not use this approach. Instead, many of the final applicability criteria are based on permit restrictions, while others are being finalized as subcategorization criteria based on operating conditions. See Sections IV.A.1 and IX.A of the preamble for a discussion of the retrospective applicability criteria.
One-third Sales Criterion
Commenter 9666 supported the general intent of the Agency's proposed one-third sales criterion with respect to NGCC units, however commenters (8909, 8918, 8952, 9425, 9665, 9666, 9678, 10095, 10098, 10135, 10398) expressed concerns that this criterion may not, as a practical matter, exempt all simple cycle turbines for future operations.
Commenter 10240, a preconstruction permitting authority, supported the proposed one-third sales criterion and believed this provision is sufficient to support the increased harnessing of renewable energy sources while allowing simple cycle turbines to perform their critical role providing stability to the grid.
Commenter 9426 stated that if EPA chooses not to provide an explicit exclusion in any final rule for simple-cycle turbines, the commenter recommended the agency adopt the one-third of potential electric output sales applicability criterion on a three-year rolling average basis.
 Commenters (3862, 6505, 8973, 9001, 9201, 9407, 9428, 9595, 9601, 9678, 9767, 9779, 10038, 10086, 10097, 10100, 10238, 10240, 10358, 10520, 10554) supported the EPA's proposed one-third sales criterion. Commenter 9678 asserted this exclusion provides operational flexibility that ensures grid reliability.
Commenter 10952 supported limiting applicability of the proposed NSPS for natural gas EGU CTs to units supplying more than one-third of potential electric output and more than 219,000 MWh net annual electric output to the grid because inefficiencies inherent with lessor operation would present compliance problems with the proposed standard 
Commenters (9201, 9733) supported the one-third sales criterion because it is consistent with longstanding Acid Rain provisions. Commenter 9733 also supported the proposed additional flexibility included in the applicability determination for the one-third sales criterion that allows use of the actual "design electrical output efficiency."
Commenter 10395 stated that based on their understanding, if SC CTs installed by the commenter in the future are constructed for the purpose of supplying, and actually supply, 219,000 MWh or less of electricity to the grid on a 3-year-rolling average basis, they should be exempt from the proposed rule and the stringent CO2 emission standards. The commenter stated that EPA should confirm in its final rule that EPA concurs with this analysis, if EPA decides not to completely exclude SC CTs from KKKK regulation. The commenter believed that this would provide greater flexibility to use simple cycle CTs to meet the essential purposes noted above.
Commenter 9499 stated that if the EPA does not exempt SC units from the new standards, the Agency should at a minimum consider regional differences in assessing the reasonableness of the 33% capacity factor limitation, allowing for a higher capacity factor in wind rich arid regions of the country, and propose a CO2 emission limit that can be met by SC units.
Commenter 10395 requested that the EPA further clarify the meaning of supplying more than one-third of potential electric output and more that 219,000 MWh net annual electric output to the grid. This commenter stated his understanding of the one-third sales criterion and requested that the EPA confirm in the final rule concurrence with the commenter's interpretation that if a unit provides less than 219,000 MWh net output to the grid on a three-year rolling average basis, the unit is not subject to the proposed standard. 
Commenters (8952, 9407, 9425, 9665, 10095, 10098, 10929) believed that EPA should not arbitrarily restrict the operation of simple cycle turbines to less than the one-third sales threshold because such a restriction could adversely affect grid reliability as dispatchers who need simple cycle turbines to support significant renewable generating capacities cannot use those permitted simple cycle assets above the threshold because the simple cycle turbines cannot comply with the proposed standard. Commenters (8952, 9407, 9425, 10095, 10098) asserted that the EPA has not included in the record analyses of effects (on GHG emissions, grid reliability, and compliance with renewable portfolio standards (RPS)) of the one-third sales criterion related to anticipated demand growth for renewables and the effective limit on use of simple cycle assets to reliably incorporate renewable assets into energy markets implementing RPS. 
Commenters (8918, 8937, 8952, 9425, 9592, 9665, 9666, 9678, 9780, 10095, 10098, 10100, 10102, 10395, 10929, 11184) recommended complete exemption of simple cycle units, but stated that if a sales criterion is retained in the final rule, the one-third sales criterion should be revised to further ensure grid reliability. Commenter 9425 stated that the proposed standard was based on the efficiencies achieved by combined cycle units and requested that the EPA clarify the compliance status of a less-efficient simple cycle unit that exceeds the one-third sales criterion and that has an average emission rate above the proposed standard. 
Commenters (8952,9665) believed that in the absence of a full exemption for simple cycle combustion turbines, the sales criterion should be structured as a sliding scale function so that the particular applicability threshold for a given simple cycle unit is proportionate to the unit's efficiency; units with higher efficiencies would have correspondingly higher sales criteria. The commenters provided examples based on highly efficient simple cycle machines operating at 1,100 pounds of CO2 per gross MW hour produced: the commenters suggested that such units should be allowed higher capacity factors than the one-third factor proposed. The commenters subsequently compared the highly efficient simple cycle turbine to less efficient units with emission rate of 1,450 pounds of CO2 per gross MW hour: the commenters suggested that the applicability threshold for such less efficient simple cycle turbines (along a sliding scale) would be 33 percent as proposed. 
 Commenters (8952, 9407, 9425, 9665, 10095, 10098, 10929) opposed the one-third sales criterion because it is based on historic generating data with fewer renewable generating assets than are expected in the future. These commenters stated that the EPA's historic analysis does not account for federal and state regulatory policies promoting renewable generation, and the commenters believe future energy markets (that may be significantly different than historic markets) should dictate appropriate simple cycle turbine capacity factors. 
Commenter 8937 stated that the 33% and 219,000 MWh applicability thresholds for simple cycle turbines reward low efficiency, smaller simple cycle units at the expense of larger high efficiency units, and the commenter opposed these applicability provisions because, the commenter asserted, these provisions restrict the ability of utilities to use the most efficient simple cycle gas turbines and are counterproductive to the EPA's objective of reducing emissions. 
Commenter 8909 opposed the one-third sales criterion because the commenter is concerned the criterion will create incentives for utilities to use less efficient, simple cycle generation and the commenter recommended establishing separate emissions standards for simple cycle units. Commenter 10052 opposed the one-third sales criterion specifically for simple cycle turbines because the commenter believed that because it will encumber the ability of utility companies to ensure system reliability and encumber their ability "to serve customers as much electricity as they want, when they want it." Commenter 10052 also stated that the sales criterion as proposed does not consider the length of time needed to incorporate new resources (such as combined cycle power blocks to displace simple cycle units being dispatched at high capacity factors) into a utility portfolio which can take in excess of five years during which time simple cycle units may need to operate above the proposed sales criterion to maintain system reliability. 
Commenters (8023, 8957, 9513, 9514, 9771) opposed the one-third sales criterion. Commenter 8957 opposed the one-third sales criterion and believed the exemption will allow owners to build generating units with significantly larger capacities than can be justified based on the current demand for electricity, thereby avoiding applicability of the standard by running the oversized units at less than one-third of their oversized, rated capacities; this commenter believed that such an "oversizing" strategy will be more economical than CCS. 
Commenter 8957 opposed inconsistent treatment of boilers and combustion turbines when applying the one-third sales criterion and believed the criterion should be based on a three-year rolling average for both boilers and combustion turbines. Commenter 8957 also opposed establishing a separate capacity factor of 20 to 40 percent for combustion turbines because it may allow turbines to avoid applicability. 
Commenter 9513 opposed the proposed one-third sales criterion because the criterion would exempt peaking units and many load following units including the new fast start combined cycle units designed to support renewables. 
Commenter 9514 opposed the one-third sales criterion in favor of specific emissions calculation procedures that accommodate cogenerating facilities and that apply to all EGUs that supply or were constructed to supply any electricity to the grid. Commenters (9514) also opposed the one-third sales criterion because this criterion will exempt peaking units that are not industrial units and have no cogeneration purpose or capacity and because this criterion will complicate regulation of existing coal- or gas-fired units that operate at capacity factors of less than one-third, since the existence of applicable section 111(b) standards are a predicate for regulation by states under section 111(d). 
Commenter (9514) recommended revising the "one-third" sales criterion to "any" sales to include fast-start CCGTs that complement the variable loads produced by renewable resources. Commenter 9514 also stated that if the EPA retains an applicability threshold based on grid sales, the agency should close a potential loophole for CCGTs (that may be constructed for the purposes of supplying low capacity factors complementary to renewable generating capacity) by referring not to a plant's "potential electric output," but to its "intended electric output." 
Commenter (8023, 9514, 9771) opposed the premise proffered by the EPA in the preamble that the one-third sales criterion "does not explicitly exclude simple cycle combustion turbines, but as a practical matter, it would exclude most of them because the vast majority of simple cycle turbines sell less than one-third of their potential electric output." Commenters (8023, 9514, 9771) opposed this premise because these commenters believe that GHG standards should apply to peaking units and that the EPA should develop GHG standards specifically for peaking units (as a subcategory of EGUs) as well as other targeted types of EGUs necessary to support emerging plans to optimize use of variable renewable resources. Commenters (8023, 9771) emphasized the need for flexible, dispatchable, generating assets in service territories with progressive RPS. Commenter 8023 pointed out that use of variable output renewable resources requires a thermal generation fleet that is both flexible enough to sit idle or at a very low output to allow absorption of the solar energy generated at midday, and equally capable of quickly contributing up to 13,000 MW of firm, dispatchable resources between 4:00 and 8:00 PM, as the sun sets and peak evening demand occurs. Commenters (8023, 9771) believe that the proposed applicability criteria are incompatible with developing the suite of emissions standards necessary to complement optimum use of renewables. 
Commenters (8023, 9771) stated that flexible EGUs with the ability to cycle and ramp to accommodate fluctuating renewables will have different emissions profiles compared to EGUs that are operated as either baseload or peaker units because frequent cycling and ramping will decrease thermal efficiency and increase GHG emissions per MWh compared to units providing stable baseload energy. Commenter 9771 stated that even when the flexible GHG emission sources are operated at a full steady state (e.g., during periods of no wind or solar activity), the very engineering design that enables the flexible operation may also reduce thermal efficiency. Commenter 9771 stated that newer EGU projects include multiple modules that allow incremental dispatch of the modules, each able to start and shut down quickly (often more than once per day) and rapidly ramp up and down. Commenter 9771 stated that existing units are being similarly dispatched, demonstrating the increasing need for flexibility while maintaining grid reliability as California de-carbonizes the electricity sector with greater amounts of variable renewable resources. Commenter 9771 stated that the EPA should move to regulate low capacity factor combustion units using subcategories as quickly as possible, rather than exempting any units.
 Commenter 3175 stated that under the proposed new source standards, the supply of the highest efficiency gas turbines will likely exceed the thresholds established for emissions of CO2 as the expected capacity factors would likely be greater than 40%. Commenter 3175 stated the net result might be the installation of a greater number of smaller turbines to remain below the thresholds, or the use of existing far less efficient turbines currently installed on the system. Commenter 3175 believed this would be an unfortunate and unintended result of the new regulation whereby the intent of the new source standards would be negated. 
 Commenter 9514 stated that EPA should abandon its proposal to re-define EGUs so as to exclude any unit from regulation unless it is designed to supply, and actually supplies, more than one-third of its potential electric output capacity and 219,000 MWh annually to the grid. Instead, it should continue to provide specific calculation procedures for emissions from regulated cogenerating facilities, and should apply the standards to all EGUs that supply or were constructed for the purpose of supplying any electricity for sale to the grid.
Commenter 9514 stated that approximately one-sixth of existing coal-fired EGUs would be exempt from this ruling, which is unacceptable.
Commenter 9514 believed the one-third sales criterion will act as an incentive for plant operators to serve the demand for renewable load-following generation with less efficient simple cycle technology; this commenter believed that fast-start combined cycle power blocks are an available and technically feasible option for meeting variable load-following demand. Commenter 9514 believed that the agency should abandon the one-third sales criterion and apply the rule to all sources, simple-cycle and combined-cycle alike, but within this context to apply different emissions limits depending on the numbers of hours a unit operates per year. Commenter 9514 provided figures based on emissions data from the EPA's Clean Air Markets Division; these figures indicated that since 2007 nearly 900 combustion turbines have been placed into service with emission rates ranging from 900 to 2000 pounds of CO2 per gross MWh; commenter 9514 opposed the one-third criterion because the commenter believed the criterion would exempt similar, new high-emitting units from applicability under GHG standards. Commenter 9514 asserted that the EPA did not provide a rationale for excluding peaking units with the one-third sales criterion and also asserted that the rationale for exclusion cannot be based on excess costs because, the commenter further asserted, there is no demonstrable correlation between the efficiency of a CT (within a given size class) and capital cost. Commenter 9514 also opposed the one-third sales criterion based on the commenters' analyses of CAMD data that indicated one-sixth of coal-fired EGUs fell below the one-third sales criterion during 2012; the commenter also asserted that many combined cycle units will fall below the one-third sales criterion and generally asserted that the one-third sales criterion is too broad and could allow a large portion of the power sector to avoid applicability.
Commenter 9514 noted, "if EPA applied the rule to all CTs and CCGTs, regardless of capacity factor, a proper determination of BSER would ensure that more efficient CCGT technology is required for intermediate and load-following units." Commenter 9514 further stated, "By limiting regulated sources to cover only those that supply more than one-third of their potential electric output capacity to the grid, EPA would exclude units that operate at a significant capacity for a significant portion of the year (e.g., 60 percent capacity for half the year). Such units are intermediate-load rather than peaking units, and should be subject to the standard." Therefore, commenter 9514 asked that "all EGUs that provide energy capacity to the grid [be] subject to the rule."
Commenters (8952,9665) opposed the provision to allow 219,000 MWh net electrical output per year because this criterion allows inefficient, small units to operate above the one-third sales criterion and deliver power to the grid while more efficient, large units would be restricted from providing more economical (and lower emitting) energy to the grid. 
Commenter 8937, 8952, 9499 stated that at the very least, EPA should consider increasing the sales threshold to 50% to accommodate the real world issues noted in the commenter's comment. 
Commenter (10950) stated that they strongly support excluding simple cycle turbines from the proposed rule, or alternatively, EPA could exempt SC units operating at or below a capacity factor of 50 percent to help promote the use of high efficiency SC turbines. The commenter stated that an exemption for SC units is critical because limiting the exclusion from the rule to units that supply less than 2919 hours to the grid is insufficient to cover many potential operating scenarios for SC units. 
Commenters (8952, 9678, 9425, 10095, 10098) believed the one-third sale criterion applied to simple cycle units over a three-year period will adversely affect grid reliability because of operators' uncertainty about future compliance dates and related decisions to curtail operations to increase capacity factor compliance margins (i.e., applicability margins); these commenters were also concerned that such compliance decisions by operators will drive up the cost of electricity as the most efficient new units are taken out of service to preserve compliance margins and older, less efficient units with no capacity limitations are ramped up instead. Commenter 10095 believed that if simple-cycle CTs are not excluded altogether, an exemption of 40 percent for these units is not only warranted but also necessary for grid security and reliability; commenter 10095 also said the EPA should presume that some simple cycle turbines will operate above the 40 percent threshold. 
 Commenters 9381, 9780 stated that if the EPA does not explicitly exempt simple-cycle CTs, the Agency must increase the sales limitation to 40 percent of potential electric output to provide maximum operating flexibility. This commenter also stated that the EPA must address whether simple-cycle units that exceed the sales criterion limit would be subject to an emissions limit only for those periods in which sales exceeded the limit or would the EPA invoke "once-in-always-in." This commenter asserted that the EPA cannot legally subject simple cycle units to an emissions standard that they cannot ever achieve if they exceed the sales criterion.
Commenter 7994, 8023, 9591, 9661, 9770, 9780, 10043, 10095 stated that if EPA does not explicitly exempt simple-cycle CTs, the Agency must increase the sales limitation to 40 percent of potential electric output to provide maximum operating flexibility. 
Commenter 8973 believed that all units supplying less than 40% of potential electric output -regardless of size or fuel type-should be exempted to provide greater flexibility for entities needing to install new units for peaking purposes as well as those units generally needed in response to emergency conditions.
Commenter 9667 stated that with respect to the option of changing the applicability requirements, such as increasing the 33 percent capacity factor up to 40 percent of potential electric output sales on a three-year basis, this is still insufficient to fully address the problems created by including simple cycle turbines.
Commenter 9661 believed a 40% capacity factor sales criterion is appropriate because of looming, large-scale coal plant closures throughout the United States and our country's historic trend of over-reliance on coal could require additional operation of peaking capacity to ensure grid stability after closure of the coal plants; because of increasing amounts of renewable energy; and because the 40% threshold encourages expanded use of combined cycle technologies. Commenter 9770 also supported a capacity factor exemption of forty percent on a three year basis because such an exemption is consistent with the operating permits for simple cycle generating units, it allows further support of the intermittent renewable resources required by Minnesota statutes, and it averages out market fluctuations caused by weather events and infrastructure constraints. 
Commenter 10618 primarily supported exemption of simple cycle turbines, but supported a 40% sales criterion if one will be required in the final rule. This commenter also stated that in cases where simple cycle turbines are constructed with the intent to operate prior to the future construction of a heat recovery steam generator (HRSG), such turbines should be exempted from the proposed rule until such time that construction of the HRSG and related equipment is completed and the unit commences operation in a combined cycle mode.
Commenter (9772) was concerned that EPA's proposed 33 percent capacity factor to exclude peaking units from the NSPS may not be sufficient to also exclude regulating units. The commenter stated that even the 40 percent capacity factor considered in the NSPS may not provide the flexibility for a regulating unit to fulfill its legally defined mission. The commenter requested EPA consider excluding regulating units altogether from the proposed rule. 
Commenter 9780 believed that using a 40% sales criterion could have the effect of exempting NGCC units that run at lower capacity factors. The commenter acknowledged that the flexibility afforded by the sales criterion will allow simple-cycle CTs to provide grid support services, but the commenter stated there is no reason to apply those criteria to NGCCs if it would result in exempting certain new combined cycle units from the proposed standards. The commenter stated that if the final rule does not provide a clear exemption for simple-cycle CTs, the sales criterion should be revised to exempt only simple-cycle CTs without exempting NGCCs, and the commenter stated that one way to address this concern would be to increase the potential sales applicability limit to 40 percent and divide combustion turbine technologies into two subcategories, simple-cycle and combined-cycle. 
Commenter 7540 recommended a sales threshold of 40 percent, on the proposed three-year rolling average, to determine applicability of this standard. In addition to the flexibility this threshold would provide to units that are designed to operate at capacity factors below the sales threshold, Commenter 7540 stated it would provide owners and operators with additional flexibility to optimize a unit during initial operation before being subject to the standard. Commenter 7540 stated that based on their analysis of the data EPA posted to the docket in support of the combustion turbine standard, none of the NGCC units exceed the proposed standard once they exceeded the sales threshold on a three-year rolling average basis.
 Commenter 9406 opposed the one-third sales criterion, but stated that if the final rule retains criteria for excluding peaking units, the criteria should be one-fifth of the peaking unit's potential electric output rather than one-third.
Commenter 8911 provided an analysis concluding that a 10 percent sales criterion on a 3 year rolling average is sufficient to ensure grid reliability except in instance of "dire emergencies." The commenter believed that regulators have the authority to relax regulations during such emergency periods.
Commenter 7976 recommended that plants operating at levels lower than 10% CF could be unregulated to allow more owner flexibility in technology selection because their contribution to CO2 emissions will be minor.  The commenter stated plants operating at levels above 65% CF could be unregulated to encourage construction of plants that can achieve less than 840 lb. CO2 / MWh - a level that is very challenging to achieve. The commenter stated that their suggested NSPS formula acknowledges the legitimacy of permitting the construction and operation of higher heat rate and emission rate plants when appropriate, but still reduces overall emissions by limiting operation of higher emission rate plants.
Commenter 9646 stated that EPA's proposal to exempt EGUs that supply one-third or less of their electric output to the grid is not at all appropriate. The commenter stated that one-third is a significant amount of time - 8-hours a day; the same as a full time job. The commenter recommended that EPA establish a 5 percent threshold.  
Citing a review of air permits for 35 simple cycle turbines that commenced operation between June 2006 and May 2013, commenter 9665 asserted that system operators and federally approved air quality permitting authorities recognize that new simple cycle combustion turbines will require capacity factors greater than one-third to reliably complement increasing usage of renewable resources. 
Commenter 9665 provided some alternative approaches if EPA chooses not to exempt simple cycle turbines. The commenter stated that EPA could exempt simple cycle units operating at or below 50 percent capacity, providing that total annual emissions are capped at or below the emission levels that excluded units could emit, could establish different capacity factors based on the efficiency of the simple cycle unit, or could establish an absolute tonnage per MW cap based on the nameplate or peak unit output. 
 Commenter 8952 recommended a capacity-factor exclusion of "50% as a minimum." 
Commenter 9666 stated that in general the exclusion of turbines below 73 MW (250 MMBtu/h) and those that satisfy the one-third sales criterion should eliminate some turbines that might violate the NSPS. However, the ambiguities associated with the one-third sales criterion make it difficult, if not impossible, to accurately analyze its impact on the CO2 emissions limit. This ambiguity must be clarified before it can be accurately be determined what the appropriate CO2 NSPS level should be.
Commenter 7976 stated that the most reasonable method of regulating long term compliance would be to reduce the capacity factor limit for as long as a deficiency in plant maintenance is causing an increase in the emission rate. 
 Commenter (9425) stated that EPA should consider limiting the applicability of its rule to EGUs with high capacity factors during a particular calendar year.
 Commenter (9666) generally supported the proposed applicability exemptions for low capacity factor EGUs and small combustion turbines. 
 Commenter 9771 believed that EPA should not provide an exemption for units with a capacity factor of less than 33 percent, based on a retrospective three year rolling average of operating hours. 
Commenter 7976 stated that the proposed 33% CF exclusion stands regulatory incentive on its head. It avoids regulation of the undesired high emission rate plants but imposes regulation on the desired low emission rate plants. 
The EPA completed significant analysis for this final rule and concluded that the appropriate distinction between non-base load and base load units is the use of the sliding-scale subcategorization approach. This approach provides adequate flexibility for the continued use of simple cycle units while simultaneously promoting the installation of more efficient technologies. While the EPA found that the one-third electric sales threshold would provide adequate flexibility for simple cycle units based on their historical usage, the EPA wanted to be responsive to commenter concerns that simple cycle units may be used more in the future to back up intermittent renewables. Under the sliding scale, conventional simple cycle turbines will be able to sell between 33 and 40 percent (depending on the unit) of their potential electric sales before being subject to the base load standard, the best high-efficiency simple cycle turbines will be able to sell up to 43 percent of their potential electric output, and fast-start NGCC units will be able to sell up to 49 percent of their potential electric output. Requests for 50 and even 60 percent electric sales thresholds for all units are simply not reasonable. Units selling this much electricity to the grid are serving base load demand and should be installing NGCC technology, which is both more cost-effective and more efficient at these sales levels.
Commenter 6158 stated that EPA should focus on unit output in establishing the applicability provisions regardless of whether the unit serves on-site load or delivers electricity to the grid. Commenter 8957 stated similar concerns, but added that under the proposed regulation, the owners or operators of a power plant that provides 876,000 MWh annually only needs to oversize their plants by three times to avoid applicability. Because the proposed rule requires a coal-fired plant to oversize by approximately 28 percent and install expensive auxiliary equipment in order to provide on-site sequestration at the proposed 40 percent level, the commenter stated it is more economical for plant owners and operators to oversize their potential capacity than to meet the proposed standard.
Commenter 9666 opposed the sales criterion because the commenter is concerned that using a sales criterion instead of capacity factor might allow industrial facilities to avoid compliance with this rule despite the fact that they operate at capacity factors as high or higher than EGUs selling to the grid; the commenter does not understand the rationale of a policy that would allow the owners or operators of large industrial NGCC units to circumvent the purposes of this rule. 
Commenter 9666 was also concerned that using a sales criterion instead of capacity factor might allow industrial facilities to avoid compliance with this rule despite the fact that they operate at capacity factors as high or higher than EGUs. The commenter stated that as proposed, a large NGCC unit located at a facility might operate at a very high capacity factor (e.g., 90 percent or more) and not have to comply with the GHG NSPS because most of its generation is used onsite and it does not trigger the one-third sales criterion. The commenter stated that they don't understand a policy that would allow the owners or operators of large industrial NGCC units to gain compliance with this rule. 
Commenter 10520 stated that they support the one-third sales criteria, however, they are concerned that using a sales criterion instead of a capacity factor limit might allow industrial facilities to avoid compliance with this rule. The commenter stated that, as proposed, a large NGCC unit located at an industrial facility might operate at a very high capacity factor and not have to comply with the GHG NSPS because most of its generation is used on site and it does not trigger the one-third sales criterion. 
The intent of the applicability criteria in this final rule is to cover EGUs whose primary purpose is to sell electricity to the grid, not industrial CHP units. The applicability criteria in this final rule accomplish that goal.
Commenter 9514 stated that EPA refers to "capacity factor" as an EGU's threshold energy output (MWh) to the grid. See 79 Fed. Reg. at 1459. The commenter felt that this is an odd use of the term capacity factor, which typically refers to the actual operation of a unit compared to its potential over a given stretch of time. For instance, if a unit operates at 80 percent load for 8,760 hours in a year, it would have an 80 percent capacity factor. Similarly, if a unit operated at full load for 7,008 hours, it would also have an 80 percent capacity factor.
Commenter 9514 found the EPA's use of the term "capacity factor" at 79 FR 1459 inconsistent with previous definitions of this term under 40 CFR Part 60.
The EPA agrees that our use of capacity factor in the proposed rule was not ideal. Our use of capacity factor refers to the amount of potential electric output supplied to a utility power distribution as the capacity factor. This is a shorthand for the percentage electric sales threshold. However, capacity factor can also be calculated based on hours of operation or the amount of heat input. Both of these approaches approximate, but not match the actual relevant threshold which is based on the percentage of electric sales relative to the potential electric output. In fact, in the proposed rule the EPA approximated the number of existing simple cycle units potentially impacted by the one-third percentage sales criterion, which overestimated the number of potentially impacted units. In this final rule, we have tried to consistent use percentage electric sales and not capacity factor.
Commenters (7994, 8952, 8973, 9426, 9666, 9678, 9777, 9779, 9780, 10023, 10048, 10100, 10392, 10554, 10876) supported exclusion of electricity generated as a result of a grid emergencies from counting as net sales when determining applicability, and commenter 10100 also supported the definition of "system emergency" as "any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore calls for maximum generation resources to operate in the affected area, or for the specific affected facility to operate to avert loss of load." Commenter 10100 believed this definition is appropriate because the benefits of operating these units to generate electrical power during emergency conditions outweigh any adverse impacts from short-term increases in CO2 emissions by units lower in the dispatch order. 
Commenters (9513, 9514, 8911) opposed the exclusion of grid emergencies when calculating a source's net electricity sales for rule applicability purposes because section 111 emission standards must apply continuously even during grid emergencies, and that EPA does not have the necessary authority under the Clean Air Act to suspend applicability of the standard during these periods. Commenter 9513 believed the proposed exclusion of grid emergencies is also unnecessary, as EPA already possesses an effective mechanism to address this issue while avoiding conflicting outcomes and unintended consequences: the EPA Assistant Administrator for Enforcement is delegated the authority on behalf of the United States to advise a source that the government would not sue the source for taking certain actions during an emergency. The commenter stated that this authority has been used in a variety of circumstances and provided specific examples.
Commenter 10876 stated that electricity that is generated in response to a grid emergency declared by a regional transmission organization (RTO), independent system operator (ISO), or control area administrator should be exempted from the amount that is used to determine net sales for EGU applicability. The commenter stated that this proposal is consistent with approaches that EPA has recently applied to its rulemakings for the Mercury and Air Toxics Standards (MATS) rule and the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Reciprocating Internal Combustion Engines (RICE units). Such an approach should also be applied to the new unit rules. 
In conjunction with the prospective purpose criteria, Commenter 10098 supported an "emergency conditions exemption" and requested that the EPA formulate a clear definition of what constitutes a "grid emergency."
The final rule includes an exemption for electric sales that occur as the result of a system emergency from counting towards the percentage electric sales threshold. See Section IX.B of the preamble for a discussion of emergency electricity generation.
Commenters (8937, 9320, 9425) stated that the EPA should expressly exclude periods of operation when combustion turbines fire permitted back-up fuels such as fuel oil, alternatively, EPA should further analyze CO2 emissions during oil-fired operations and propose an NSPS that adequately accounts for such periods or re-evaluate, develop and propose a separate standard for dual-fuel units that accommodates partial load operations, specific unit design, and operational site characteristics. Commenter 9425 stated that the use of oil as a backup fuel is relatively infrequent and that units also are typically subject to operating limits in air permits that restrict usage of oil while recognizing the importance of backup fuel operation. The commenter went on to say that some units may be forced to bum oil for an extended period of time, during extended shutdowns of natural gas production facilities in the Gulf of Mexico following a major hurricane. The commenter expressed concerns that this situation would result in significantly higher CO2 emission rates than allowed by the NSPS standard and preclude compliance. Therefore, the commenter suggested that the final rule provide an explicit exemption for periods when the use of a backup fuel is required to maintain grid reliability. Commenter 9320 a utility operator in Florida stated that the proposal failed to adequately consider the need for new combined-cycle CTs to operate on oil as a back-up fuel when natural gas is curtailed or supplies are disrupted during emergencies, such as hurricanes; this commenter stated that if use of backup fuels is not categorically excluded a specific standard for use of such fuels should be established. 
 Commenter 9780, 10095 stated that EPA also needs to address the fact that there are units that combust natural gas normally, but could be required to combust oil during energy periods. The commenters stated EPA should exempt from any compliance averaging calculation emissions that result when an NGCC unit runs on backup fuel oil to address emergency conditions as long as those periods comprised 10 percent or less of the unit's heat input over a three-year period. 
Commenter 8937 requested that the final rule address use of backup fuels during periods of natural gas curtailment, and the commenter recommended that the final rule exempt periods when a unit must operate on backup fuels.
Commenter 6505 recommended eliminating the compliance requirement for the periods of time when a unit is combusting secondary fuels, such as fuel oil, but still consume >90% natural gas on a 3 year rolling average. The commenter stated that this creates the possibility for an otherwise extremely efficient combustion turbine being precluded from service during reliability critical events.
Commenter 9591 interpreted the proposed provisions under 40 CFR 60.4305(c)(4) related to the 90% threshold for use of natural gas to mean that any oil fired in a turbine would be included in compliance calculations unless oil use exceeded the proposed 10 percent threshold on a rolling three-year basis. The commenter believed this language indicates a unit using more than 10 percent oil would be considered oil-fired and not covered by the proposed rule. The commenter also agreed with the EPA's assumption that new, primarily oil-fired turbines are unlikely to be constructed. 
Affected combustion turbines burning 10 percent or more non-natural gas are subject to the emission standard for the multi-fuel-fired unit subcategory. This emission standard is based on the use of clean fuels, and is readily achievable by all combustion turbines burning distillate oil.   
Commenter 8952 asserted that the 2001 to 2012 simple cycle generating data that the EPA used to characterize typical capacity factors for simple cycle turbines is atypical because these data included a severe economic recession and an expansion of energy conservation programs. Commenter 8952 stated that the 3 year averaging period has a limited benefit because capacity is forward-looking, and one year of high demand decreases the available margin over the next 2 years.
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.