Page 1 Follow-up to April 17, 2009 Meeting

May 12, 2009

Mr. K. C. Hustvedt

U.S. EPA Office of Air Quality Planning and Standards Mail Drop E143-01 Research Triangle Park, NC 27711 Hustvedt.Ken@epamail.epa.gov

Dear Mr. Hustvedt:

On December 22, 2008, in response to petitions for reconsideration submitted by the American Petroleum Institute (API), the National Petrochemical and Refiners Association (NPRA) and the Western States Petroleum Association (WSPA) among others, EPA issued proposed amendments (73 Fed. Reg. 78522 ) to the New Source Performance Standards (NSPS) for the Petroleum Refinery source category, 40 C.F.R. Part 60 Subparts J and Ja. API, NPRA and WSPA filed comments on the proposed amendments on February 5, 2009 (Docket document

EPA- HQ

- OAR -2007-0011-0311.1) and supplemented those comments on April 8, 2009 (Docket

Document EPA- HQ -OAR-2007-0011-315.1).

On April 17, 2009 we met with you and other EPA staff to discuss our supplemental comments and respond to EPA’s questions. We could not fully respond to some of EPA’s questions during the meeting. Therefore, by this letter, we are providing detailed responses to the questions raised at that meeting.

1. Provide a list and possible definitions for special flares that should be subject to reduced monitoring requirements.

Response:

a. Continuous sulfur monitoring should not be required for “low sulfur flares.” Low sulfur flares are flares where all streams that may be sent to the flare meet §60.107a(a)(3) or (b). We believe the exemptions from fuel gas sulfur monitoring in these sections should also be applied to flare gas sulfur monitoring for the same reasons the Agency cited for fuel gas combustion. See comment 4.2.4 of our original comments on these amendments.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 2 b. Continuous sulfur monitoring should not be required for flares which only handle process upset gas, as proposed to be defined 1 , because 1) of their service or 2) because routine vent gas is normally recovered 2 or 3) because the flare only receives vent gas overflow from another flare (i.e., a secondary flare as discussed in item d below). Continuous sulfur monitoring is difficult to operate, not cost effective and not BDT for flares receiving only process upset gases because of their occasional and highly variable nature. We would define these flares as follows:

Process upset flares are flares where only pilot gas, sweep gas, purge gas and process upset gas are normally combusted. Pilot, sweep and/or purge gas flows to

these flares are at known rate s and sulfur levels.

As an example of the potentially high costs and minimal benefits of this requirement, one member company has a refinery that has flare gas recovery on all 9 of its flares. The site sends gas to the flare only during very infrequent process upsets where the flow exceeds the capacity of the recovery system. The typical minimum cost to install an H 2 S CEMS is hundreds of thousands of dollars. Depending on the pipe diameter, need for platforms and shelters, location, etc. this cost can be even larger. In other words, the cost to this site to install monitors that most of the time will sit there and not monitor anything is on the order of several millions of dollars. This level of monitoring is not cost-effective for this refinery and certainly does not represent BDT for such flare systems.

The situation described above exists at a number of refineries. While some refineries may have one or two common flare systems with cascaded flares (i.e., an H 2 S CEMS would only be necessary on the lead flare), other refineries may have a number of stand-alone flare systems handling only process upset gas, all of which would need to be equipped with H 2 S CEMS to comply with NSPS Ja.

Safety issues are also a concern. Refiners would need to have vigorous safety precautions on the procedures to install, maintain, and certify these CEMS in those cases where high H 2 S levels may be resident in the lines. While these risks can be managed, for a cost, it is imprudent to expose sites and workers to these risks unnecessarily.

In order to comply with the root cause failure analyses requirements in the Consent Decrees (CDs), refiners have developed comprehensive and effective procedures that make use of process operating data and knowledge of the sulfur content in the streams. Refiners do not need an H 2 S CEMS on the flare stack in order to know when a process upset has occurred and when the 500

lbs of SO 2 emissions has been exceeded.

EPA recognized during the CD negotiation process that it made little sense to require an H 2 S CEMS on a flare that is designed to handle only process upset gas, in part because of difficulty of maintaining equipment that normally never sees any flow. In fact, the CDs specifically exempt systems with flare gas recovery from the requirement to install an H 2 S CEMS. For instance, one CD states:

1 Pilot, sweep and/or purge gas flows to these flares are at a constant rate and known (and compliant) sulfur levels and their presence does not justify continuous sulfur monitoring.

2 Recovery systems may be out- of -service for short periods due to upsets and malfunctions or required maintenance.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 3 "Use of a flare gas recovery system on a flare obviates the need to continuously monitor and maintain records of H2S in the gas as otherwise required by 40 CFR §§60.105(a)(4) and

60.7"

Consequently, the need to install and maintain monitors cannot be justified on systems that are equipped with flare gas recovery and handle only process upset gases. Furthermore, if EPA's goal is to encourage the installation of additional flare gas recovery, adding a requirement to install CEMS on flares with flare gas recovery will only increase the cost of these systems and act as a disincentive to this objective.

c. Continuous flow monitoring should not be required for small flares. We would define small flares as flares designed to combust <500,000 SCFD above their pilot, sweep and purge gas flows. Since such flares could not exceed the RCA analysis trigger of 500,000 SCFD, continuous flow monitoring would serve no purpose. See comment 4.3.4 from our original

comments on these amendments.

d. Continuous flow monitoring should not be required for secondary flares. A secondary flare is a flare that receives flow, other than pilot, sweep and purge gas flows, only when another flare is overloaded. The monitoring instrumentation on the primary flare would serve to quantify the sulfur level of any gas reaching the secondary flare and the flow monitoring for the primary flare would identify any events exceeding the 500,000 SCFD RCA trigger. Thus, separate monitoring of secondary flares is redundant and of minimal added value.

e. Continuous flow monitoring should not be required for process upset flares (as defined in Item b above). Water seal monitoring or other on/off flow monitoring 3 is adequate for identifying when an event occurs and engineering analysis can estimate the amount of gas released from orifice calculations and process conditions. See comment 4.3.3 from our original

comments on these amendments.

f. Continuous flow monitoring is unnecessary and wasteful for flares that only handle loading emissions. Loading is a repetitive operation and the vapor flow is a function of the material being loaded, the loading rate and the loading temperature and thus is not amenable to change. Thus, repeated determinations of the flow rate serve no purpose. A onetime RCA/CAA analysis should be required in the Flare Management Plan if there is a possibility that 500,000 SCFD or more of loading vapor could be sent to the flare and no continuous monitoring should be required.

g. In comment 4.5.2 of our original comments on these amendments we argued that temporary flares should be excluded from Subpart Ja applicability. In the event they are not totally excluded, they should be exempted from the continuous monitoring requirements, unless they are being used as backup for a Subpart Ja flare and the monitors for that flare can be used. Spending millions of dollars to monitor flares used for six months or less is not BDT and not justified. A simple requirement to address the use of these flares in a flare management addendum would be the most feasible approach to minimize emissions and reflect BDT for such flares.

3 For instance, if only pressure relief valves (PRV) are connected to a flare, monitoring the PRVs (e.g., outlet pressure or temperature, depending on the situation) could be a sensitive indicator of flow to the flare.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 4 2. Consider if accepting an RCA approach works for flare gas recovery (FGR) system maintenance. Provide information on FGR system maintenance practices.

Response: Individual FGR systems must be totally or partially shutdown when maintenance is required to prevent equipment failures and/or to maintain capacity and efficiency, particularly of the compressors and their drivers. For example, routine replacement of poppet valves 4 is required for reliable and efficient reciprocating compressor operation. Planned shutdowns or bypasses of FGR systems will often also be required to generate a flow of gas to a flare if RATA testing is required for the continuous sulfur and/or H 2 S monitors and, if the proposed Part 60 Appendix B Performance Specification 17 and Appendix F Procedure 4 is finalized and applies to the flare continuous flow monitor(s). As proposed, P-4 Section 8.3 paragraph 6 and Section 8.7 paragraph 1, would require quarterly RATA testing, presumably at high flare flow rates, of the continuous flow monitor. This would require significant flaring during the testing and expose personnel to considerable safety risk as discussed in Item 5 below. To avoid this flaring and these safety concerns the Agency should exempt flare flow monitors from the PS-17 and P-4 requirements.

Such FGR outages for preventive maintenance are infrequent, but RATA testing and parameter monitor testing, on the other hand, are proposed as quarterly activities 5 . During FGR outages sources often cannot meet the 162 ppm H 2 S limit that Subpart Ja imposes, since sour gas is often collected by FGR systems as the most efficient way to capture that gas and send it to amine treatment. Thus, as currently constituted, Subpart Ja may have the unintended consequence of increasing the number of FGR system failures (malfunctions) as sites attempt to extend run lengths to coincide with unit turnarounds, etc.. Since monitor testing is required by the regulation (or State regulation or the CDs), where bypassing is required to do that testing,

sources will have to violate Subpart Ja’s H 2 S limit during testing, an unreasonable and untenable

situation.

Using an RCA/CAA analysis to address these situations provides no relief from the H 2 S emission limit because the outage is not related to a process upset, the only exception to the H 2 S limit for Subpart Ja flares. We believe an allowance of up to 20 days per year is needed to assure FGR systems are properly maintained. If , as has been indicated, the Agency is unwilling to specifically provide for these necessary outages, it should formally recognize their validity by specifically incorporating them into the flare management plan requirements (i.e., require the Flare Management Plan identify the kinds of preventive maintenance and monitoring testing that is required for FGR systems and steps that will be taken to minimize flaring and sulfur emissions during those outages). We also made specific suggestions for recognizing the necessity of such outages in Comment 4.4 of our original comments on these amendments.

4 Poppet valves are used in most piston engines to open and close the intake and exhaust ports in the cylinder head. The valve is usually a flat disk of metal with a long rod known as the valve stem out one end. The stem is used to p ush down on the valve and open it, with a spring generally used to close it when the stem is not being pushed on.

5 Avoiding this flaring is one of the reasons we also recommend CGA testing, rather than RATA testing for the sulfur analyzer,

in Comment 5 be low.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 5 3. Provide details of continuous monitoring that is used in place of continuous flow monitors for flares that normally have no flow.

Response: In some cases flares only receive flow when another flare is overloaded. In those cases, the flow monitor required by Subpart Ja on the primary flare would indicate whether the 500,000 SCFD RCA/CAA trigger was exceeded for both flares and the sulfur monitor on that primary flare would provide the information needed for determining if the 500 lb/day RCA/CAA trigger is exceeded for that event. Thus in this situation, no separate monitoring of the secondary flare is needed or justified.

In other situations where there is normally no flow to a flare, sources monitor the flare header pressure and water seal level as an indicator of when flow to the flare occurs. This procedure has proven quite reliable in California refineries. The technique is only usable in flares equipped with water seal drums. The flare gas piping is introduced into these drums as a dip leg and the height of water in the drum serves to seal the gas from going to the flare. If the pressure in the flare header exceeds the back pressure imposed by the water, the seal is broken and the gas goes to the flare. These seals are virtually 100% effective.

Water seals in flare systems are set at varying depths depending on many factors. For instance, if the flare serves atmospheric tankage a back pressure of 0.5 psi is often all that can be allowed due to the design pressure of the tankage. If only process equipment is served, somewhat higher backpressures (e.g., 1 or 2 psi) may be acceptable. Flare system backpressures are kept low because higher backpressures would mean lower pressure streams could not be safely disposed of during emergencies and because the higher the backpressure, the more and the larger safety valves must be for any particular relieving load.

Because of differences in instrument capability and other factors, pressure is normally used as the primary indicator that a water seal is “blown” (i.e., there is flow to the flare), rather than level, though level is usually also monitored. The pressure that indicates flow to the flare is the difference in pressure between the inlet and the outlet of the water seal. Normally, the outlet pressure is atmospheric, but may be slightly negative due to the chimney effect of the flare stack or slightly positive due to purge gas flow. Once the outlet pressure is determined for no flow operation of a particular flare, only the inlet pressure needs to be monitored. The inlet pressure that indicates flow to the flare is unique to each water seal drum design, the height of the water seal in the drum and the mechanism by which the water level is maintained. Therefore, the pressure that indicates flow must be identified by the source for each such drum, though its determination is a straightforward engineering evaluation.

4. How have sulfur and flow analyzers been spanned under CDs or other rules? Can we recommend a span requirement that should be put in the rule?

Response: Because of the wide variability in flare gas line sizes, pressures, temperatures, compositions, flow rates, and sulfur levels, the different techniques used to measure sulfur, and the variety of detailed regulatory requirements associated with these measurements, every flare monitoring installation is highly customized. Our members report that because of this individuality, it is not possible to set a generic span requirement for sulfur monitors. Generally, sources establish a sulfur range that is a wide as possible without requiring multiple analyzers,API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 6 considering the range of sulfur contents in the gases that might go to the flare and the regulatory requirements that must be met.

Subpart Ja sulfur monitors have to be able to assure compliance with the 162 ppm H 2 S standard and to measure the lowest sulfur level that would generate 500 lb/day of SO 2 for a particular flare if that level were continuously maintained for 24 hours. Quantifying very high sulfur levels with the same analyzer that can accurately monitor for those low sulfur levels is generally not possible (and not necessary to identify if the 500 lb/day limit has been exceeded during high sulfur events). Thus, where high sulfur levels must be quantified, multiple analyzers are needed. To meet some state requirements such multi-analyzer systems have been developed (at very high costs) in a few cases, but normally the sulfur analyzers are matched to the regulatory requirements plus whatever higher sulfur levels the selected monitoring and sampling technology is capable of measuring. As indicated above, this is a case- by -case decision, which for Subpart Ja flares will need to consider both Subpart Ja and State requirements, as well as flare system characteristics. Thus, we recommend that sources be allowed to set the span requirements for the flare sulfur monitors they use to comply with Subpart Ja and record that span and the basis for their choice in their Flare Management Plan.

For flow monitors, however, broad range instruments are available and they can measure flows for most flare situations. The BAAQMD requirement is:

12-11-501 Vent Gas Flow Monitoring: Effective 180 days after adoption of this rule, the owner or operator of a petroleum refinery shall not operate a flare unless vent gas to the flare is continuously monitored for volumetric flow by a device that meets the following requirements:

501.1 The minimum detectible velocity shall be 0.1 foot per second.

501.2 The device shall continuously measure the range of flow rates corresponding to velocities from 0.5 to 275 feet per second in the header in

which the device is installed.

501.3 The device shall have a manufacturer’s specified accuracy of ±5% over the range of 1 to 275 feet per second.

The SCAQMD requirement from Rule 1118 Appendix A is:

Velocity Range: 0.1

- 250 feet per second

Repea tability: ± 1% of reading over the velocity range

Accuracy: + 20% of reading over the velocity range of 0.1

- 1 ft/s and ± 5% of reading over the velocity range of

1

- 250 feet per second

Even with this broad range, there are occasions, typically during major malfunctions, when the flare flow rates can exceed the monitor capability. None-the-less, this range has proven more than adequate to identify 500 lb/day SO 2 releases and flow events exceeding 500,000 SCFD and would allow quantification of events greatly exceeding those values. We therefore recommend the Agency specify the flare flow measurement requirement as covering a range of at least 0.1 to 250 feet per second. Using the slightly broader BAAQMD span, might cause some sites to have to replace units that are limited to 250 feet per second, for no significant benefit and specifyingAPI/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 7 an exact range would make installations meeting the BAAQMD requirement unacceptable for Subpart Ja compliance.

5. Would it make sense to check sulfur analyzers with cylinder gas rather than running RATAs for flares with no or small normal flows? Are there safety issues associated with handling high H 2 S cylinder gases?

Response: RATA testing of flare sulfur analyzers is generally considered impractical and can be unsafe and unreliable. Furthermore, it would require significant unnecessary flaring to provide adequate flow for RATA testing, which in some jurisdictions is not allowed or would require approval. Thus, flare sulfur analyzers typically are calibrated using cylinder gases. The safety concerns associated with RATA testing flares primarily occur 1) because of the potential radiant heat impact to the testing personnel, should a emergency flaring event occur while the testing is occurring and test personnel are close to the flare stack (where the analyzer is required to be located), 2) due to potential H 2 S and other exposures from collecting samples from flare headers (leakage of gas from the flare to the atmosphere during testing), 3) due to the potential to leak air into the flare header if, as is possible, the sampling location is operating under vacuum, potentially causing a flammable mixture and 4) because some flare headers operate at elevated temperatures. While these can also be a concern when using cylinder gas, it is less of a concern, because cylinder testing takes much less time, is performed at the analyzer house not at the flare header (i.e., farther from the flare tip), and because cylinder gases are piped to the analyzer and thus connections only have to be opened when a cylinder is changed. While there is some concern with handling high sulfur cylinders, our members indicate these concerns are not insurmountable. Area monitors can be used in the area where the cylinders are stored and used, to warn of any leakage and personnel safety can be addressed through procedures and use of protective equipment.

Cylinder gas checks also are more reliable than RATA testing. Because of the typical low pressures in flare headers, the variable temperature and flow and the possible presence of entrained liquids, catching representative flare gas samples for RATA testing can be quite difficult and time consuming. The sophisticated, highly engineered, dedicated analyzer sample probes used by the analyzers can overcome these problems, but they are difficult to address when manually sampling, such as during RATA testing. Furthermore, sulfur species tend to react with sample system materials and it is difficult to be sure a RATA sample is valid. Finally, flare gas sulfur levels are often outside the range of the Appendix A test methods used for RATA testing and thus of questionable validity.

For all of these reasons, most jurisdictions have accepted cylinder gas testing as the safest and most appropriate way of checking these analyzers. The specific sulfur specie used and the concentrations are specific to each individual installation. Thus, we believe it is impossible to proscribe the details of the cylinder test in a way that would be workable for even a majority of these analyzers and we therefore recommend that the specifics of the sulfur analyzer cylinder gas procedure be developed by the site and the analyzer manufacturer and be recorded in Flare Management Plan. Current experience proves each of these analyzers must be custom engineered and each will have its own optimum calibration procedure.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 8 6. Develop a proposal for an SO 2 mass flare standard as an alternate to the 162 ppm H2S

standard.

Response: In the Refinery CDs, EPA agreed that in some situations where the concentration of

H 2 S in the vapors routinely going to a flare is above the 162 ppm H 2 S standard but the flow rate and resultant mass emissions are very low, sites could demonstrate compliance with the CD via

an alternative limit of 500 lbs SO 2 /day em itted from the flare (excluding process upset gas) as measured using an H 2 S CEMs per §60.105(a)(4) and a continuous flow meter. This alternative means of compliance was established in recognition of the very poor cost-effectiveness associated with the large capital and operating costs required to recover these low flow streams. The CDs specifically identified the flares to which this limit applied. That is, this alternative limit was not available to all flares at the refinery, but only to designated flares.

Based upon the CD precedent and the logic underlying it, we believe a mass limit should also be allowed as an alternate to the 162 ppm H 2 S limit in Subpart Ja. As requested in our meeting, we have investigated whether the 500 lb/day provided by the CDs could be reduced and suggest the following.

300 lbs SO 2 /day a flare system (excluding process upset gas, as measured using an H 2 S CEMS on the flare gas and a continuous flow meter).

Th is limit would apply to a flare system. That is, interconnected flares would be capped

at the 300 lbs SO 2 /day limit from H 2 S, preventing a site from potentially splitting the

flow to several flares.

This limit, as in the CDs, is based on the H 2 S combusted in the flare and is separate from the total TRS or Total sulfur RCA/CAA trigger. This is appropriate, since this limit is an alternate to the 162 ppm H 2 S limit in the flare gas.

7. Develop a proposal for demonstrating compliance for 40-100 MBTU/hour process heaters, when they are using the NOx turndown mass emission limit. EPA believes that a CEM is necessary.

Response: We concur with EPA’s conclusion that continuous NOx analyzers are not justified for process heaters designed to fire between 40 and 100 MMBTU/hr. In the final Subpart Ja, the Agency requires biennial performance tests as the compliance basis for these heaters. Under the proposed amendments, us e of a continuous NOx analyzer would be allowed as an alternate (e.g., where such an analyzer is present because of a State rule or permit) and we strongly support this proposal.

If a NOx turndown mass limit is allowed by the final amendments, we believe the same approach should be used. That is, biennial testing at the maximum firing representative of the turndown operation or use of a continuous NOx analyzer should be allowed as the basis for demonstrating compliance. Thus, if the turndown mass limit would apply below 50% firing, the source should do a biennial performance test at maximum representative firing (e.g., approximating 100% of design) and at 50% firing to confirm the NOx emission factors at those firing rates. The NOx emission factor determined at the 50% firing rate would be used to determine the mass emissions during turndown operation. Again, continuous NOx monitoring would be allowed as an alternate for establishing the NOx emission rate where such a monitor is present.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 9 8. Confirm the 60 ppm NOx limit referenced in comment 5.2.8.1 is a typo and should be 40

ppm.

Response: We have reviewed comment 5.2.8.1 of our original comments on these amendments and confirm that the NOx limit cited should have been 40 ppm rather than 60 ppm.

9. Provide data to support position that certain induced draft process heaters should be considered as forced draft, rather than natural draft. In particular, address our comments on down-firing burners.

Response: In comment 5.1.1 of our original comments, we requested that process heaters with induced draft fans and downward firing burners be classified as forced draft heaters, as follows.

in the case of a downwardly fired process heater (such as a steam-methane reformer - hydrogen plant - heater) induced draft furnaces have the same issues as forced draft heaters, because the induced draft fan is used to move the combustion gases through the burner and through the entire process heater, not just the convection section. Thus, this type of process heater should be added to the forced draft process heater definition.

Further discussion of this item with our combustion experts identified that this issue was not fully presented in the original comment. Steam reformer process heaters typically have induced draft fans and downward firing burners and the fan is therefore “pulling” the combustion air into the radiant section, but the primary reason they cannot meet the 40 ppm natural draft NOx limit using only burner modifications is because they operate at significantly higher temperatures than other refinery process heaters (i.e., 1900-2000 °F versus <1700 °F). Placing these process heaters in the forced draft category would make them subject to the 60 ppm standard, rather than the 40 ppm standard, and that level can generally be achieved without add-on controls.

10. Comment on the Environmental Improvement Project (EIP) position that the NOx limit for Fluid Catalytic Cracking Units (FCCUs) should be lower.

In Docket Document EPA- HQ -OAR-2007-0011-0130.1, Pages 9-10 an argument is presented by EIP that the NOx limit for FCCUs should be set at 20 ppmv, not the 80 ppmv in Subpart Ja. EIP offered two comments to support their position. Neither comment compels changes to the promulgated NOx limit of 80 ppmv, averaged over 7 days.

First, EIP argued that EPA should apply the FCCU NOx limit not only to newly constructed FCCUs (as proposed by EPA), but also to reconstructed and modified FCCUs. Based on additional analysis, the Agency concluded in the final rule that a NOx emissions limitation would be technically feasible and cost effective for reconstructed and modified FCCU 6

. Therefore, the final rule applies the 80 ppmv standard to constructed, reconstructed, and modified FCCUs. EIP should have no further quarrel with this result, as EPA modified the scope of the rule according to EIP’s suggestion.

Second, after reciting data from the Centers for Disease Control and Prevention and a recent EPA Inspector General’s report as to the potential hazards to health and the environment associated with NOx emissions, EIP asserted that:

6 73 Fed. Reg. 35847-35848.API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 10 Given the significant hazards to human health and the environment posed by NOx emissions, the most stringent option of limiting refinery emissions to 20 ppmv, which EPA acknowledges is “technically feasible,” should be adopted. EPA has failed to justify its proposal to adopt the least stringent option of limiting refinery NOx emissions to 80

ppmv.
EIP provides nothing more in support of this argument. Based on this comment, EPA conducted additional analysis to investigate the adequacy of the 80 ppmv proposed NOx emissions limitation. The analysis included a relatively high limit of 150 ppmv, a limit of 80 ppmv, and a lower limit of 20 ppmv. EPA determined that the first two limits should be achievable using some combination of combustion controls. EPA also concluded that the 20 ppmv limit would require add-on control technology, such as LoTOx or SCR. All of these options were determined to be technically feasible. The absolute cost effectiveness of these options in terms or dollars per ton of NOx removed ranged from $750/ton to $3,600/ton. The incremental cost effectiveness of the 20 ppmv option was determined to be approximately $6,000/ton.

The Agency further observes that the energy requirements of the add-on controls required to meet the 20 ppmv option would result in additional indirect emissions of various pollutants, including NOx. On the basis of this analysis, the 80 ppmv option was determined to be both technically feasible and cost effective for new, reconstructed, and modified FCCUs. EPA concluded that the 20 ppmv option was not cost-effective given the incremental cost effectiveness (as compared with the 80 ppmv option) of $6,000/ton 7

. In light of this analysis, EIP’s comment should be rejected. To begin, fairly read, EIP’s comment amounts to the assertion that NOx emissions are potentially harmful to health and the environment and, therefore, EPA must select the most stringent control alternative. In essence, EIP is arguing that cost plays no role in determining BDT and, instead, EPA’s sole mission is to determine and then prescribe the most stringent limit that is technically feasible.

This argument is patently wrong. The statute unambiguously requires EPA to consider cost in determining BDT:

The term “standard of performance” means a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated. 8 [emphasis added].

Not surprisingly, from the inception of the NSPS program and through the decades that this program has existed, EPA has considered cost in determining BDT. Thus, EPA was well within its authority to rely on its cost effectiveness analysis in deciding the appropriate FCCU NOx

standard.

7 Id.

8 CAA § 111(a)(1)API/NPRA/WSPA Follow-up to April 17, 2009 Meeting

Page 11 More generously, EIP’s comment might be construed as arguing that costs are relevant in setting the standard, but that EPA’s cost -effectiveness conclusions are in error. If this is really what EIP meant, it should have said so. Since it did not, EPA is under no obligation to respond. See, e.g., NRDC v. EPA, No. 07-1151 (D.C. Cir. 2009), slip op. at 6- 7 (“Agency officials should not have to wade through reams of documents searching for ““implied” challenges.”).

Even if we assume that EIP implicitly commented on EPA’s cost effectiveness analysis and that these comments should be given credence, the Agency made a reasonable, fact-based determination that wholly supports the 80 ppmv standard. As noted above, the Agency’s analysis showed that the incremental cost effectiveness of moving from an 80 ppmv to a 20 ppmv standard was approximately $6,000/ton of NOx removed. By way of comparison, in the recent NSPS for stationary spark ignition internal combustion engines, the Agency estimated a monetized benefit of $2,800 per ton of NOx removed 9 . Taken together with the additional emissions associated with the increased energy demand of add-on controls, the incremental costs of imposing a 20 ppmv FCCU NOx standard are clearly excessive 10 . Even with the benefit of the doubt, EIP’s comments fail to demonstrate that the 80 ppmv standard is legally flawed.

Should you have any questions, please contact Ron Chittim at (202) 682-8176. As always, we would be happy to meet with the Agency to clarify any of these items.

Regards,

Ron Chittim

API

202/682-8176 chittiim@api.org

cc R. B. Lucas

U

. S

. EPA Office of Air Quality Planning and Standards Mail Drop E143

- 01 Research Triangle Park, NC 27711

l ucas.bob@epa.gov

9 73 Fed. Reg. 3568, 3587 (Jan. 18, 2008).

10 We also believe that there are additional costs, not reflected in the current EPA analysis that would show lowering the NOx standard to be more costly than the Agency estimate.