Daily Rules, Proposed Rules, and Notices of the Federal Government
We seek comment only on the aspects of the final MATS and Utility NSPS rules specifically identified in this notice. We are not opening for reconsideration any other provisions of MATS or the Utility NSPS at this time.
Categories and entities potentially affected by today's notice include:
This table is not intended to be exhaustive but rather to provide a guide for readers regarding entities likely to be affected by this action. To determine whether your facility, company, business, organization, etc. would be regulated by this action, you should examine the applicability criteria in 40 CFR 60.40, 60.40Da, or 60.40c or in 40 CFR 63.9982. If you have any questions regarding the applicability of this action to a particular entity, consult either the air permitting authority for the entity or your EPA regional representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).
Do not submit information containing CBI to the EPA through
In addition to being available in the docket, electronic copies of these proposed rules will be available on the Worldwide Web (WWW) through the Technology Transfer Network (TTN). Following signature, a copy of each proposed rule will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at the following address:
The Administrator signed MATS and the Utility NSPS on December 16, 2011, and the final rules were published in the
Today, we are granting reconsideration of, proposing, and requesting comment on the following limited set of issues: (1) Certain revised new source standards in MATS, (2) requirements applicable during periods of startup and shutdown in MATS, (3) startup and shutdown provisions related to the PM standard in the Utility NSPS, and (4) definitional and monitoring provisions in the Utility NSPS. We are also proposing certain technical corrections to both MATS and the Utility NSPS.
This notice is limited to the specific issues identified in this notice. We will not respond to any comments addressing any other provisions of MATS or the Utility NSPS.
The impacts of today's proposed revisions on the costs and the benefits of the final rule are minor. We expect that source owners and operators will install and operate the same or similar control technologies to meet the proposed revised standards in this notice as they would have chosen to comply with the standards in the February 2012 final rule.
The EPA received petitions requesting reconsideration of aspects of the new source emission limits in the final MATS rule. We are granting reconsideration of certain new source emission limits, as discussed below, and we invite comment on the proposed provisions in today's notice.
The EPA received petitions for reconsideration asserting that the Agency did not use all the data in the record from the best performing sources in establishing certain final new source emission limits for coal- and oil-fired electric utility steam generating units (EGUs). Specifically, the petitioners maintained that the EPA did not consider all of the data in the record when establishing emission standards for filterable PM and hydrogen chloride (HCl) applicable to new coal-fired EGUs and for filterable PM applicable to new solid oil-derived fuel-fired EGUs.
In light of petitioners' assertions, we reviewed the available emissions information in the record for all the new source standards. We determined that we did not use all the data in the record in establishing the new source emission limits for filterable PM and HCl applicable to new coal-fired EGUs and for filterable PM applicable to new solid oil-derived fuel-fired EGUs. We also identified a few additional new source limits for which we did not use all of the data in the record when setting the standards in the final rule. We are proposing to revise the sulfur dioxide (SO
We also solicit comment on possible revisions to the Hg limit applicable to low rank virgin coal-fired EGUs based on additional data in the record. See "Reconsideration of the National Emission Standards for Hazardous Air Pollutants (NESHAP) Maximum Achievable Control Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating Units, Proposed Rule" in rulemaking docket EPA-HQ-OAR-2009-0234; "MATS Reconsideration: Beyond-the-Floor Memorandum" available in rulemaking docket EPA-HQ-OAR-2009-0234.
The proposed revised new source CAA section 112(d) emission standards are presented in tables 1 and 2 of this preamble. The Agency derived these limits by first calculating the floor standards and then assessing whether a more stringent beyond-the-floor standard is appropriate.
We are also reconsidering the SO
At the time of the final rule, we believed the unit on which we based the SO
As an initial matter, nothing in the CAA precludes the EPA from identifying a source in another source category as the best controlled similar source. However, we believe that it is appropriate in this case, where we have considerable data on EGUs, to base the new source standard on the best performing unit that is an EGU. This is also consistent with our intent in the final rule, as we thought the unit we had selected was, in fact, an EGU. For these reasons, we are reconsidering the SO
The EPA is also reconsidering the emission limit for Hg for new coal-fired EGUs in the units designed for the coal [?] 8300 Btu/lb (non-low rank virgin coal) subcategory. Some petitioners asserted that this limit, as finalized, was too low for emissions to be reliably measured in a manner that would allow sources to operate their control technology in a way that ensures compliance with the standard. Specifically, petitioners maintained that sorbent trap monitoring systems could not provide sufficiently timely Hg data at the new source level for sources to make adjustments to the EGUs and attendant air pollution control devices (ACPDs) to ensure compliance with the standard and that Hg continuous emissions monitoring systems (CEMS) were not capable of measuring Hg at the new source limit. The petitioners indicated that reliable and frequent emission measurements are needed to maintain the operation of Hg control technology at performance levels set in the final rule.
As we explained in the record to the final rule, owners and operators of new EGUs in the non-low rank virgin coal subcategory could use the sorbent trap monitoring systems to demonstrate compliance with the new source Hg standard because of the potential for a longer sample collection period associated with sorbent traps and their inherent lower emissions detection capability.
As described in the final rule, when establishing emission limits for pollutants, we calculated a representative detection limit (RDL) and then compared the UPL-determined emission floor with a value three times the RDL (3 X RDL), and we set the final limit at the higher of the two numbers. We did not follow that procedure for sorbent trap monitoring systems when setting Hg emission limits as we did not believe sorbent trap monitoring systems were constrained by method detection limits, since operators could increase the sample collection time up to 14 days to guarantee collection of a measurable quantity of mercury with appropriate accuracy. We continue to believe that the promulgated Hg limit for the non-low rank virgin coal subcategory is measurable using a sorbent trap monitoring system.
As noted, however, petitioners have indicated that the long sorbent trap sampling times that may be necessary to measure at the final new source level do not allow sufficiently frequent emissions feedback such that a source could take corrective action and avoid violations of the emission limit within the prescribed compliance time.
We understand that Hg emissions can vary over time, and we acknowledge the value of frequent feedback of emission measurements. We also understand that frequent feedback may be desirable and, at times, necessary to optimize the operation of generation or control technology in order to maintain emissions at or below the standard. The sorbent trap monitoring method required in the MATS rule allows sampling for as long as 14 days. In the final rule, we assumed that most sources would leave the sorbent traps in as long as needed--up to 14 days--to ensure they had no measurement issues. Based on the petitions for reconsideration, we understand that sources will most likely use a shorter sampling period, perhaps as short as 30 minutes. The shorter sampling periods will provide more constant feedback on Hg emissions, which will help the source ensure that it is in compliance with the Hg emission limit, for which compliance is determined on a 30-day rolling average.
Given the petitioners' stated need for more frequent Hg emissions information, we re-evaluated whether detection level issues arise when shorter sampling periods, such as 30 minutes, are employed by sorbent trap monitoring systems. Although the shorter sampling period is adequate to provide information needed to optimize the operation of Hg control technology, we believe the reduced sampling period results in a reduced quantity of collected Hg which constrains the sorbent trap monitoring system by a minimum detection limit. For additional information, see "Determination of Representative Detection Level (RDL) and 3 X RDL Values for Mercury Measured Using Sorbent Trap Technologies" in rulemaking docket EPA-HQ-OAR-2009-0234. Specifically, we believe detection level issues may arise from using a sorbent trap when short sampling periods (e.g., 30 minutes) are used, and that, as such, the UPL-calculated floor value should be compared against the 3 X RDL value to account for the shorter sampling periods. We solicit comment on this proposed revised approach in light of the information provided by petitioners regarding the need for prompt Hg emissions information.
Our review of the data in the record shows that for reasonable, shorter sampling conditions--30-minute samples obtained at a sampling rate of 0.5 liter per minute--the UPL-determined new source Hg limit is less than the 3 X RDL value. Therefore, we are proposing to set the Hg limit for the non-low rank virgin coal subcategory at the 3 X RDL value.
Although the value of the resulting limit we are proposing today is higher than that in the final rule, we do not expect this change to alter the emission control strategy of a new EGU, as both emission limits result in Hg removal efficiency in excess of 97 percent. However, the proposed change will improve EGU owners' and operators' ability to track emissions and take preemptive actions to ensure compliance. Based on information provided by the petitioners, our experience, and the National Institute of Standards and Technology's recently confirmed capability to certify Hg calibration gas generators down to 0.2 micrograms per cubic meter (mg/m
Please refer to the memo "Data and Procedure for Handling Below Detection Level Data in Analyzing Various Pollutant Emissions Databases for MACT and RTR Emissions Limits" (docket entry EPA-HQ-OAR-2009-0234-20062) for a discussion of the RDL approach generally, and the memo "Determination of Representative Detection Level (RDL) and 3 X RDL Values for Mercury Measured Using Sorbent Trap Technologies" (rulemaking docket EPA-HQ-OAR-2009-0234) for a discussion of our approach for establishing an RDL for Hg. The proposed limit is presented in table 1 of this preamble.
We are granting reconsideration of the finalized new source integrated gasification combined cycle (IGCC) limits. The EPA used the permit limits from IGCC EGUs that are permitted but not yet constructed as the basis for some of the final new source IGCC emission limits. Some petitioners asserted that the EPA did not use this approach in the notice of proposed rulemaking and that they therefore were deprived of the opportunity to comment on this approach.
Although we indicated that we considered establishing standards based on IGCC permits at proposal, we are granting reconsideration on the new source IGCC limits so that the public has an additional opportunity to comment on the limits and the approach.
Specifically, we request comment on the proposed new source IGCC standards, which are unchanged from the final standards promulgated for these units on February 16, 2012. These proposed new source limits are presented in tables 1 and 2 of this preamble.
The MACT floor level of control for new EGUs is based on the emission control that is achieved in practice by the best controlled similar source, as determined by the Agency, of each HAP for the different subcategories. After the EPA establishes MACT floor levels, CAA section 112(d)(2) requires the EPA to consider whether more stringent beyond-the-floor standards should be established. Under that section, the Agency must consider "the cost of achieving such emission reduction, and any non-air quality health and environmental impacts and energy requirements" before it may establish a standard that is based on a beyond-the-floor level of control.
For most of the new source standards addressed in this proposal, we have not identified additional technologies or HAP emission reduction approaches that would achieve HAP reductions greater than the new source floors for the subcategories, other than multiple controls in series (e.g., multiple scrubbers in series or multiple PM controls in series), which we consider to be unreasonable from a cost perspective. We are therefore proposing to adopt the floor level of control for all but one of these standards. We are proposing a beyond-the-floor standard for HCl emissions from coal-fired EGUs. Summaries of the EPA's beyond-the-floor evaluations for the new source standards addressed in this proposal are provided below. Additional detail of these analyses, including a discussion of costs and non-air quality health and environmental impacts, is provided in the "MATS Reconsideration: Beyond-the-Floor Memorandum" available in rulemaking docket EPA-HQ-OAR-2009-0234. We request comment on all aspects of our beyond-the-floor analysis. Specifically, we solicit comment on whether there are any control technologies or HAP emission reduction practices that have been demonstrated to achieve HAP reductions at levels lower than the standards proposed in this notice consistently and in a cost-effective manner. Comments should include information on emissions, pollutant control efficiencies, operational reliability, current demonstrated applications, and costs.
a. Beyond-the-floor analysis for PM from coal-fired EGUs. It is commonly accepted that a baghouse fabric filter (FF) is the technology that provides the best level of PM emission reduction for coal-fired EGUs. Newly constructed coal-fired EGUs will be expected to install FFs to meet the new source NESHAP PM limit that we are proposing in this notice and the applicable NSPS limit. We have considered available options that would allow a new source to achieve greater emission reductions than those achieved in practice by the best controlled source. The EPA is aware that some EGUs have installed downstream secondary "polishing" PM control devices to provide for incremental PM reductions beyond what is achieved by the primary PM control device. However, those "polishing" PM control devices are most often installed for one of two purposes: (1) To augment the control of an underperforming or undersized primary control device or (2) to allow for injection of activated carbon or other powdered sorbent so that the fly ash and the sorbent remain separated for eventual storage, disposal, or re-use. Given that a new coal-fired EGU would have the opportunity to design the primary PM control device to meet the new source emission limit, we can see no justification for including in the design a secondary downstream "polishing" PM control device. Such a device would add considerable cost to the project, and the incremental cost-effectiveness would not be reasonable. See "MATS Reconsideration: Beyond-the-Floor Memorandum" in rulemaking docket EPA-HQ-OAR-2009-0234.
b. Beyond-the-floor analysis for Hg from new coal-fired EGUs designed for coal [?] 8300 Btu/lb. The proposed new source Hg emission limit for EGUs firing non-low rank virgin coal is based on the use of the 3 X RDL approach. As explained above, there is concern that a lower emission limit could not be reliably measured with sufficient frequency to allow consistent and timely compliance. For this reason, we are not proposing a limit based on a beyond-the-floor level of control, and, instead, we are proposing to establish the standard at the MACT floor level.
c. Beyond-the-floor analysis for SO
d. Beyond-the-floor analysis for PM from solid oil-derived fuel-fired EGUs. This analysis is very similar to that which was presented earlier for PM emissions from coal-fired EGUs. Given that a new solid oil-derived fuel-fired EGU would have the opportunity to design the primary PM control device to meet the new source emission limit, we can see no justification for including in the design a secondary downstream "polishing" PM control device. As with the coal-fired source, such a device would add considerable costs to the project, and the incremental cost-effectiveness would not be reasonable.
e. Beyond-the-floor analysis for SO
f. Beyond-the-floor analysis for PM from continental liquid oil fuel-fired EGUs. The proposed new source filterable PM emission limit for continental liquid oil-fired fuel is based on an EGU which uses an electrostatic precipitator (ESP). Distillate oil-fired facilities do not need add-on PM controls, as their emissions are inherently low, and residual oil-fired units cannot use FFs for PM control due to concerns about bag contamination and fire safety. ESPs are the best filterable PM control technology for liquid oil fuel-fired EGUs. Given that a new continental liquid-oil fuel-fired EGU would have the opportunity to design the primary PM control device to meet the new source emission limit, we can see no justification for including in the design a secondary downstream "polishing" PM control device. Such a device would add considerable costs to the project, and the incremental cost-effectiveness would not be reasonable.
g. Beyond-the-floor analysis for HAP emissions from IGCC EGUs. We have no data upon which to assess whether or not technologies exist that can provide additional HAP control beyond the proposed new source emission limits for new IGCC units. Accordingly, we are not proposing to establish beyond-the-floor emission limitations for these pollutants for new IGCC units. We request comment on whether the use of any control technologies or practices have been demonstrated to consistently achieve in a cost-effective manner, emission levels for similar sources that are lower than those proposed for new IGCC sources in this proposal. Comments should include information on emissions, pollutant control efficiencies, operational reliability, current demonstrated applications, and costs.
h. Beyond-the-floor analysis for HCl emissions from coal-fired EGUs. For HCl, the EPA's revised floor analysis for coal units--discussed above--resulted in a revised MACT floor of 2.0E-2 pound per megawatt-hour (lb/MWh). We have estimated that a new coal-fired EGU would need to remove HCl in the range of 81.0 to 96.6 percent (depending upon the initial chlorine (Cl) content of the fuel) in order to meet this revised MACT floor level of control for HCl emissions. We also note that it is reasonable to expect that in most, if not all, cases, advanced FGD control technology (such as a wet-FGD scrubber or a high efficiency SDA) would be required as a result of other federal requirements--specifically a prevention of significant deterioration (PSD) best available control technology (BACT) analysis. More detailed discussion may be found in the memo "MATS Reconsideration: Control Technology Needed to Meet New Source Limits" contained in rulemaking docket EPA-HQ-OAR-2009-0234.
A high efficiency SDA is less costly than a wet-FGD, and we think it likely that some new sources will be able to comply with PSD/BACT requirements using that less expensive option.
We, therefore, are proposing to set a beyond-the-floor HCl emission limit for new coal-fired EGUs at 1.0E-2 lb/MWh. We believe that a new EGU firing lower Cl-content coal would need to achieve a minimum of 90 percent control to meet this proposed limit and that a new EGU firing a higher Cl-content coal would need to achieve a minimum of 98 percent control to meet the limit. We believe that this beyond-the-floor emission limit is cost-effective because it does not involve additional cost, as we expect that any new unit will install at least a high efficiency SDA to comply with other CAA requirements.
We also considered a beyond-the-floor emission limit by assuming installation of a wet-FGD scrubber, which generally achieves greater HCl reductions, but at a greater cost, than a high efficiency SDA. We understand that some new coal-fired EGUs will likely be required to install this type of advanced FGD technology for SO
For coal-fired EGUs, the final rule regulates HCl as a surrogate for acid gas HAP, with an alternative equivalent standard for SO
We have evaluated the levels of control that would generally be needed to meet the proposed emission limits for new sources and have compared those to the levels of control needed to meet the new source emission limits in the final MATS rule. We compared the level of control needed by analyzing requirements for a new hypothetical 500 MW facility. The comparison led us to conclude that new EGUs would need to be designed to use the same types of emission control technologies to meet the proposed new source limits as would have been needed to meet the final MATS new source limits. More detailed discussion of this evaluation may be found in the memo "MATS Reconsideration: Control Technology Needed to Meet New Source Limits" contained in rulemaking docket EPA-HQ-OAR-2009-0234.
Nothing in the statute requires the EPA to demonstrate that an existing source is able to meet all of the new source limits. Nevertheless, we note that based on our review of the data EPA collected as part of the 2010 ICR process, at least eight existing non-low rank virgin coal-fired EGUs and one low rank virgin coal-fired EGU have reported short-term stack test data that demonstrate that these EGUs have in practice achieved the new source limits proposed in this notice (considering all of their submitted data). Furthermore, for HCl (as well as the SO
We provided several monitoring options for the filterable PM standard in the final rule, including quarterly stack testing, PM CEMS, and PM continuous parameter monitoring system (PM CPMS) with annual testing. For many reasons, including continued use of already-installed instruments on some EGUs, direct (as opposed to parametric) measurement of the pollutant of concern, and continuous feedback for process control, we believe that many EGU owners or operators will choose to use PM CEMS to monitor the proposed filterable PM limit.
We solicit comment on whether to retain the quarterly stack testing compliance option, as this option may not be necessary because continuous, direct measurement of filterable PM or a correlated parameter is available and likely to be used by most sources to monitor compliance with the revised standard.
With respect to the PM CPMS compliance option for new EGUs, we considered three approaches to establish an operating limit based on emissions testing. The first approach would allow an EGU owner or operator to use the highest parameter value obtained during an individual emissions test when the result of that individual test was below the limit as the operating limit. The
Even though this rule proposes the first approach, we solicit comments on the appropriateness of any of the three approaches to establish a PM CPMS operating limit for new EGUs.
In addition, this rule proposes to require emissions testing after each exceedance of the operating limit for new sources. This rule proposes a number of consequences if the PM monitoring parameter is exceeded. First, the EGU owner or operator will have 48 hours to conduct an inspection of the control device(s) and to take action to restore the controls to proper operation, if necessary, and 45 days to conduct a Method 5 compliance test under the same operating conditions to verify ongoing compliance with the filterable PM limit. Within 60 days, the EGU owner or operator will have to complete the emissions sampling, sample analyses, and verification that the EGU is in compliance with its emissions limit, as well as having to determine an operating limit based on the PM CPMS data collected during the performance test. The EGU owner or operator would then compare the recalculated operating limit with the existing operating limit and, as appropriate, adjust the numerical operating limit to reflect compliance performance. Adjustments could include applying the most recently established value or combining the data collected over multiple performance tests to establish a more representative value. The EGU owner or operator would then apply the reverified or adjusted operating limit value from that time forward.
Second, this rule proposes to limit the number of exceedances of the site-specific CPMS limit leading to follow-up performance tests in any 12 month process operating period and that an excess of this number be considered a violation of the standard. This presumption of violation could be rebutted by the EGU owner or operator, but would require more than a Method 5 test as a basis for the rebuttal (e.g., results of physical inspections would also need to be included). This additional information is necessary since a Method 5 test could not be conducted during or immediately following the discovery of exceedances and would not necessarily represent conditions identical to those when the exceedances occurred. The basis for this part of the proposal is that the site-specific CPMS operating limit reflects a 30-day average that should represent an actual emissions level lower than the three test run numerical emissions limit since variability is mitigated over time. Consequently, we believe that there should be few, if any, exceedances from the 30-day parametric limit and there is a reasonable basis for presuming that exceedances that lead to multiple performance tests to represent poor control device performance and to be a violation of the standard. Therefore, this rule proposes that PM CPMS exceedances leading to more than four required performance tests in a 12-month process operating period is presumed to be a violation of this standard, subject to an EGU owner or operator's ability to rebut that presumption about process and control device operations in addition to the Method 5 performance test results. We solicit comment on this proposed revised approach.
The CAA section 112(a)(4) defines a new source as a stationary source "the construction or reconstruction of which is commenced after the Administrator first proposes regulations under this section establishing an emissions standard applicable to such source." The EPA views the new source trigger date (the date EPA "first proposes regulations") to be the date EPA first proposes standards under a particular rulemaking record. (74 FR 21158). In this case, EPA first proposed standards for EGUs on May 3, 2011, and although we are proposing revisions to certain new source standards, the rulemaking record remains the same. As such, we are not proposing to revise the trigger date for determining whether a source is a new source. Any source which commenced construction or reconstruction after May 3, 2011 is subject to the new source standards.
Furthermore, it is the EPA's technical judgment that new sources would need to adopt the same or similar emissions control strategies under the amended standards as they would have under the promulgated standards. The revised standards remain stringent and can be met, in our view, using the same or similar control strategies as would have been required to meet the standards in the final rule.
The EPA received petitions asserting that the public lacked an opportunity to comment on the startup and shutdown provisions in the final MATS. Petitioners also assert that the definitions of "startup" and "shutdown" in the final MATS and the provisions for work practice standards did not adequately address applicability to certain types of units, fuels considered "clean," and operational limitations for certain EGU types and/or pollution control devices.
We proposed numerical standards for startup and shutdown periods, and in response to comments on the proposed rule we changed those standards in the final MATS to work practice standards. Among other things, the work practice standards required sources to combust clean fuels during startup and shutdown periods and required sources to engage APCDs when coal or oil was fired in the EGU. (See 77 FR 9380-83). We also revised the definitions of "startup" and "shutdown" after considering comments we received. Although we revised these provisions in response to comments, we are granting reconsideration on this issue to provide an opportunity for comment on the final startup and shutdown standards and those we have revised and propose today. For further discussion of petitioners' concerns and these proposed revisions, please refer to the memo "Startup and shutdown provisions" in rulemaking docket EPA-HQ-OAR-2009-0234. Below we summarize the startup and shutdown revisions proposed today.
We are proposing to revise the definitions of startup and shutdown in this reconsideration notice as set forth in 40 CFR 63.10042. Petitioners asserted that the final rule's definitions of startup and shutdown were not sufficiently clear, should accommodate operation of
We are proposing several revisions to the finalized work practice standards. Petitioners asserted that the final rule's work practice standards should include certain additional fuels as "clean fuels" and recognize operating limitations of certain EGU types and APCDs. Specifically, petitioners contend that the list of clean fuels required for use during startup in order to minimize emissions should include synthetic natural gas, syngas, and ultra-low sulfur diesel (ULSD). The EPA has also been informed since the final rule that propane is used to startup some EGUs and has been requested to consider it as a clean fuel. Petitioners additionally contend that the standards need to recognize operating conditions for FBC EGUs that inject limestone for acid gas control, selective non-catalytic reduction systems (SNCRs), selective catalytic reduction systems (SCRs), and other systems.
In this reconsideration notice, we are proposing to add certain synthetic natural gas, syngas, propane, and ULSD to the list of clean fuels. We solicit comment on our understanding of clean fuels for startup and shutdown.
We are also proposing to require EGU source owners and operators, when firing coal, solid oil-derived fuel, or residual oil in the EGU during startup or shutdown, to vent emissions to the main stack(s) and operate all control devices necessary to meet the operating standards that apply at all other times under the final rule (with the exception of limestone injection in FBC EGUs, dry scrubbers, SNCRs, and SCRs). Owners and operators of EGUs are responsible for starting limestone injection in FBC EGUs, dry scrubbers, SNCRs, and SCRs as expeditiously as possible, but, in any case, when necessary to comply with other standards applicable to the source that require operation of those control devices.
Additionally, we are proposing to revise the final rule's work practice requirements to recognize constraints of certain EGUs and APCDs. The proposed revised standards allow limestone injection to start after appropriate temperatures have been attained in FBC EGUs that inject limestone for acid gas control and allow SNCR, SCR, and dry scrubber systems to start as soon as technically feasible after the appropriate temperature has been reached.
For more discussion of each of these issues, please refer to the memo "Startup and shutdown provisions" in rulemaking docket EPA-HQ-OAR-2009-0234.
The EPA understands that at an IGCC EGU, syngas is generated in the gasifier and combusted in the turbine. During the startup and shutdown periods, some or all of the syngas produced may not be combusted in the turbine. We are proposing two options for IGCC EGUs for handling syngas not fired in the combustion turbine: (1) syngas must be flared, not vented or (2) syngas must be routed to duct burners, which may need to be installed, and the flue gas from the duct burners must be routed to the heat recovery steam generator. We are soliciting comments on the need to flare the unfired syngas, if it is more appropriate to require routing of the unfired syngas back into the system for all IGCC EGUs, and on the costs of adding duct burners, should they be required.
We solicit comments on the proposed revisions to the startup and shutdown requirements set forth in this notice.
Petitioners state that because the final Utility NSPS rule contains a definition of "natural gas" that was not included in the proposed rule, they were not able to comment on the definition. Further, petitioners maintain that the definition established in the final rule is not a "logical outgrowth" of the proposed rule. Although the definition was changed between proposal and final based on public comment, we are re-proposing the definition of natural gas that was in the final Utility NSPS to allow additional opportunity to comment.
We are also proposing several additional amendments so that synthetic natural gas will receive similar treatment as natural gas. We seek comment on all aspects of these additional amendments. First, consistent with the NESHAP definition, we are proposing to clarify the definition of coal to include synthetic natural gas derived from coal. As such, we are also proposing to add synthetic natural gas to the opacity exemption in paragraph 40 CFR 60.42Da(b)(2) since facilities burning synthetic natural gas would otherwise be subject to an opacity standard. In addition, we are also proposing to replace "natural gas" with "gaseous fuels" in 40 CFR 60.49Da(b) so facilities burning desulfurized coal-derived synthetic natural gas are not required to install an SO
Additional proposed amendments include amending the definition of an IGCC to be similar to the corresponding NESHAP MATS definition. Potential language is as follows:
Integrated gasification combined cycle electric utility steam generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine that burns a synthetic gas derived from coal and/or solid oil-derived fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year in a combined-cycle gas turbine. No solid coal or solid oil-derived fuel is directly burned in the unit during operation.
We believe that this would address the issue of IGCC facilities switching applicability between the stationary combustion turbine NSPS (40 CFR part 60, subpart KKKK) and the Utility NSPS. However, we are specifically requesting comment if it would be more appropriate to maintain the existing NSPS IGCC definition and add "startup and commissioning, shutdown" as suggested by one petitioner. Potential language for the alternate definition is as follows:
Integrated gasification combined cycle electric utility steam generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation.
In addition, the rationale for the filterable PM standard startup and shutdown work practice provision discussed in the NESHAP portion of this notice also applies to the filterable PM startup and shutdown standards in the Utility NSPS. Therefore, we are proposing to amend both the emissions
Finally, we are proposing to clarify that owners/operators electing to use PM CPMS to monitor PM emissions are exempt from the requirement to install a continuous opacity monitoring system (COMS) and would be allowed to elect to use alternate opacity monitoring procedures currently allowed in the Utility NSPS.
On April 19, 2012 (77 FR 23399), we issued a technical corrections notice addressing certain corrections to the February 16, 2012 (77 FR 9304) MATS.
In this notice, we are proposing several additional technical corrections. These amendments are being proposed to correct inaccuracies and other inadvertent errors in the final rule and to make the rule language consistent with provisions addressed through this reconsideration. We are soliciting comment only on whether the proposed changes provide the intended accuracy, clarity and consistency. These proposed technical changes are described in tables 3 and 4 of this preamble. We request comment on all of these proposed changes.