Date: October 11, 2012

To: Brenda Shine, EPA/OAQPS/SPPD

From: Jeff Coburn

Subject: Meeting Minutes for October 11, 2012, Meeting Between the U.S. EPA and Representatives of the Petroleum Refining Industry

On October 11, 2012, representatives of the U.S. Environmental Protection Agency (EPA) and their contractor (RTI International) pa rticipated in a meeting with representatives of the American Petroleum Institute (API), the American Fuel & Petr ochemical Manufacturers (AFPM), and the petroleum refining industry. The na mes and affiliations of the participants are
included in Attachment 1 . The major discussion poi nts are provided below.

Sector Rule Package

Industry representatives asked about the stat us of the Sector Rule package. The EPA stated that the Sector Rule package was curr ently at the Office of Management and Budget (OMB) and that it was anticipated that OMB would ta ke the full 90 days to review, so the rule is likely to be released near the end of December.

Industry asked specifically about the current provisions for delayed coking units (DCU). The EPA indicated that the rule currently at OM B included a venting pressure limit for the coke drum as well as an alternative temperature lim it based on the saturated steam temperature at the pressure limit; the facility can chose the paramete r it would prefer to monitor. The EPA noted that there were still uncertainties with the analysis of the source test data and were unsure if these data can be used to support th e position that there is not an emissions reduction when reducing the allowable drum venting pressure from 5 pounds pe r square inch (psig) to 2 psig. If draining is initiated shortly after venting, the emissions fr om the drum vent would be lower, but the emissions from the drain pit area likely to be hi gher. The higher the drum pressure/temperature when venting is initiated, the higher the greate r the expected emissions, but these emissions may be released mostly from the vent (if draining is not initiated qu ickly) or from the drain and pit area (if draining is initiated quick ly). If the drum is vented to the closed blowdown system longer, these emissions would be captured rath er than emitted. Industry representatives stated that they would arrange a meeting with coker experts to help the EP A better understand the operations of the units tested. In response to industry ques tions, the EPA provided a brief description of the impact modeling assumptions used to determine the incremental costeffectiveness of the DCU contro l options. The industry representa tives requested a copy of the impacts documentation so they could provide comments on the costs assumptions prior to proposal.2 Industry representatives then asked about the provisions for startup and shutdown included in Sector Rule package. The EPA stat ed that the Sector Rule package included provisions for shutdown of a sulfur recovery plan t; during shutdown of a su lfur recovery unit the tail gas could be sent to a th ermal oxidizer operated at a minimu m specified temperature or to a flare. For fluid catalytic cracking units (FCCU), an alternative limit to the 1-hour CO emissions limit was being provided for startup; the altern ative limit was a minimum oxygen content in the exhaust gas (as an indicator of complete combus tion). The industry representatives asked about
maintenance allowances or alternative limits for periods when FCCU feed hydrotreater was down for maintenance [requested as one of th e 40 CFR Part 60 Subpart Ja (Refinery NSPS) reconsideration issues]. The EPA indicated that there were no provisions for alternative emission limits during these types of maintenance periods.

Flare Combustion Efficiency

Industry representatives provide d a presentation on the concept of allowing refineries to develop flare-specific plans to ensure adequate combustion efficiency is maintained for each
flare. Details of this discussi on are included in a separate memo randum that summarizes all of the industry meetings regarding flare com bustion efficiency. See memorandum from Jeff Coburn, RTI International, to Andrew Bouc hard and Brenda Shine, EPA/OAQPS/SPPD, Meeting Minutes for Meetings Between the U.S. EPA and Petroleum Refinery Industry Representatives regarding Potential Flare Pe rformance Standards: December 8, 2011; March 21, 2012; October 11, 2012; February 19, 2013; and March 19, 2013 , dated March 28, 2013.

Subpart Ja

Industry representatives indicate d that they have several issu es with the final Subpart Ja rule that was recently published. First, there are issues related to the in clusion of interconnected
flares within the definition of flares and how this impact s the monitoring requirements ( e.g. , total flow to the flare when there are multiple flare tips in the affected fl are facility). Industry representatives also noted that there were i ssues with “temporary” interconnections or connections to temporary flares. EPA indicated that it may be po ssible to address many of these issues through guidance. For example, guidan ce could be given with respect to acceptable monitoring locations, the distinct ion between interconnected flares and cascaded flare systems, etc., and that such guidance can be provided mo re quickly than technical corrections. The EPA
noted that real life scenarios of interconnected flare systems, like those provided regarding flare combustion efficiency, would be useful to bett er understand the issues and to determine the appropriate path forward; the industry representatives agreed to prepare case study examples.

Second, industry representatives expressed concern regarding th e definition of DCU because the inclusion of piping and other specif ic equipment suggests that any addition of a sampling line, instrumentation, or safety valve w ould be an increase in emissions (from fugitive components covered by 40 CFR Part 60, Subpart GGG/GGGa) and would tr igger a modification under Subpart Ja. According to th e industry representatives, this has the effect of creating a “quick trigger” for DCU.

Third, industry representatives requested clar ification regarding th e different compliant
dates based on the different definitions for DCU. Based on preamble discussion, the newest3 definition is characterized as providing detail to the unit defi nition, not necessa rily changing what was considered to be part of the unit. Industry representatives asked if the fugitive components that they are concerned about would be considered part of the DCU only under the most recent (newly published) definition of DCU. The EPA indicated that was their understanding/intent.

Fourth, industry representatives expressed concern regarding the requirements for the oxygen (O 2 ) monitor specifications for smaller proce ss heaters when a NOx continuous emission monitoring system (CEMS) is not present. Typically, process O 2 monitors are not the same as
CEMS O 2 monitors. The rule refers to these monitors as simply O 2 monitors (not CEMS), but
cross-references O 2 CEMS requirements for performance specifications and relative accuracy tests. Industry representatives stated that existing process O 2 monitors may need to be replaced
with CEMS-caliber O 2 monitors (or new monitors added) to meet the cross-referenced CEMS requirements. EPA indicated that this was not the intent and that the O 2 monitor was expected to be a continuous parameter monitoring system (CPMS) rather than a CEMS.

Heat Exchange System Amendments

Industry representatives asked about the stat us of the heat exchange system (HES) amendments. The EPA noted that the package wa s nearing completion, but was still a month or two from going to OMB. In any event, the final amendments would not be completed prior to the October 29, 2012, compliance date. The EPA stated that some of the issues, such as sampling in a representative riser, were minor and that the ex isting rule can be interpreted to allow this. The EPA also noted that sample coolers were neve r considered HES and that these systems would not need to be monitored. The proposed amen dments provided an alternative quarterly monitoring frequency at a lower detection level; this provision did not receive any adverse
comments and will be included in the final HES amendments. The proposed rule also included
water methods as an alternativ e to the El Paso stripping colu mn method. Currently, the EPA does not expect to finalize the water method altern atives based on the comments concerning the difficulty with full characterization of all compou nds potentially present in the cooling water. The EPA noted that suggestions to limit the target analyte list were not acceptable. API/AFPM indicated that they may provide f eedback regarding the need (or la ck of need) for water methods.

Follow-up Items

 EPA. Provide documentation of DCU impacts.

 API/AFPM. Arrange meeting with delayed coking unit experts to discuss source test data anomalies and potential reasons for the anomalies.

 EPA. Review flare combustion efficiency plan information a nd provide comments/ questions to API/AFPM in a pproximately 2-3 weeks (one week prior to next flare combustion efficiency working group meeting).

 API/AFPM. Develop specific interconnect ed flare case study examples to focus a discussion of issues concerning the Subpart Ja requirements for interconnected flares.

 API/AFPM. Provide feedback regarding not in cluding water method alternatives in the heat exchange system package.Attachment 1 Participants in October 11, 2012 EPA/Refining Industry Meeting

Industry Representatives Matt Todd, API John Wagner, API Bob Hermanson, BP Clay Freeberg, Chevron George Graham, ExxonMobil Charlie Bennett, Marathon Petroleum Erin Tullos, Phillips66 Frank Tracy, Phillips66 John Askounis, Phillips66 Shari Keller, Shell Norm Morrow, Fresh Air Consulting

U.S. EPA Representatives
Andrew Bouchard
Brenda Shine Penny Lassiter Peter Tsirigotis (for portions)
Sue Stahle Jan Tierney

RTI International (EPA contractor)
Jeff Coburn