                                                                               
MEMORANDUM   


TO:		Amy Hambrick, EPA/OAQPS/SPPD/FIG

FROM:	David Hendricks, EC/R, Inc.

DATE:	April 22, 2016

SUBJECT:	Summary of the January 28, 2016 Meeting with the American Petroleum Institute (API) and the U.S. Environmental Protection Agency 
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I.	INTRODUCTION

The American Petroleum Institute (API) requested this meeting with EPA to present an overview of their comments on the September 18, 2015 proposed Oil and Natural Gas Sector NSPS (80 FR 56593), draft CTG (80 FR 56577), proposed Source Determination Rule (80 FR 56579), and proposed FIP for EPA's Indian Country Minor NSR program. This summary addresses the discussion on the first three actions.

II.	ATTENDEES

The following is a list of participants in the meeting.

U.S. Environmental Protection Agency
Bruce Moore
Greg Nizich
Cheryl Vetter
Matthew Witosky
Lisa Thompson
Amy Hambrick
Jerri Garwood (by phone)
Alex McPherson
Beth Miller
Jodi Howard
Charlene Spells
David Cozzie
Eric Goehl
Susie Waltzer (by phone)
Jameel Alsalam (by phone)

API and Member Organizations
Mike Ford, Hess
Tom Monahan, XTO
Phil Norwood, ERM
Brad Morello, Shell
Dana Wood, BP
Grover Campbell, Devon
Greg Johnston, Chesapeake
Mike O'Connor, XTO
Matt Todd, API
Dennis Newman, Oxy
Shankar Ananthakrishna, Chevron
Vanessa Ryan, Chevron
John Wagner, API
Andrew Baker, Encana
Jeff Adams, BP
Laura Perry, ConocoPhillips
Andy Woerner, ERM

EC/R Incorporated
David Hendricks (by phone)

III.	SUMMARY OF DISCUSSION

Bruce Moore opened the meeting and explained to the attendees that since the EPA is in the post-proposal phase of the NSPS, CTG and Source Determination Rule, EPA personnel would listen to their comments but cannot respond to any of the issues raised. However, the EPA welcomed the comments. The attendees offered the following comments.

Source Determination Rule
 Expressed opposition to proposed option 2. 
 Agreed with EPA to be mindful of the direction the DC Circuit provides that a source for permitting purposes should comport with the common sense notion of `plant'; an overarching concern in terms of aggregation of source.
 Asserted proposed option 1 without revision and proposed option 2 would violate the above provision.
 When revising the rule, asked the EPA to be mindful of the meaning of `adjacent' as explained in the 6th circuit Southern Petroleum decision. 
 Stated that an arbitrarily chosen distance should not be used to define `adjacent'. 
 Strongly agreed that, with regard to minor sources, NSPS and NESHAP work well but stated minimal extra pollution control can be had by putting these requirements on title V affected facilities.
 Claimed EPA misconstrued some state's source determinations as detailed in their written comments. For example, noted that PA's rule is more complicated. 
 Supported the EPA definition of `service site' as same as in the NESHAP, but proposed using `facility' as defined in the NESHAP with some modification to better define many activities.
 Proposed option 1 is insufficient for source determination. Cannot presume that all sources, for example, within a (1/4) mile can be aggregated. Believed that inside (1/4) mile, the regulating agency should be allowed to make the source determination and (1/4) mile should be the maximum distance. 
 Suggested regulatory language for a 2-step process to determine contiguous  -  first, operations separated by at least (1/4) mile are not contiguous or adjacent and, second, operations within (1/4) mile are continuous/adjacent only if two additional are criteria met: First, operations are physically touching or only separated by happenstance, for example, separated by a road, river or railroad. Second, operations meet the common sense notion of `plant'.  Noted many states now operate this way, so would not be a big change for industry.
 Alternatively to the above, supported Anadarko's language  -  contiguous or adjacent properties means surface site areas within a fixed building, structure, facility or installation including permanent grade or cleared area for such building, etc. that share an edge or boundary, physically touch and are adjoining or physically abutting.
 Stated would need a 1-year transition period if option 2 is adopted or option 1 without revision, because permitting time needed could change depending on the type of permit required; some states will need to revise their statutory language. 
 Retroactive concern, for example, that if you have a well field with old well fields, drill a new well, draw (1/4) mile circle around that well and it pulls in 4-5 other existing wells: how do those existing wells affect minor/major status of new well? Believed this is a concern of states also and a burden on resources.
 Noted that no industry supported option 2 and of state and tribal comments 75% were opposed.
 Asserted that applying option 1 within (1/4) mile may involve cross jurisdictional issues between 2 or more states and tribes, becoming a permitting nightmare. Noted that there may be different ownership of land vs leases; surface leases and mineral leases are typically split; multiple owners of different mineral leases; multiple interest owners in single facility and multiple owners of minerals below. 
 Noted that ownership changes frequently and would be required to re-aggregate at those times. 
 Ownership can change over time on projects lasting a number of years and well drilling can take place over many years with years of no drilling in between.
 Also noted that two sites may be connected with an unconnected site (such as a homestead) in between so this would be counter to the commonsense notion of `plant'.

NSPS Proposal
 Expressed concern regarding changes to subpart OOOO that will be effective retroactively. 
 Regarding storage vessels, asked EPA to consider allowing an option to opt out of the rule for equipment like pneumatic pumps and LDAR requirements where states have enforceable equivalent programs.
 Asked for a 1-year phase-in for implementation of OOOO, particularly for LDAR and pumps; the usual 60 days for NSPS is too short a time for leaks. Already a backlog since proposal date to be dealt with and industry and contactors need to ramp up for LDAR program, training, etc. 
 Stated depending on pneumatic pump requirements are finalized, if required to control, could take some planning time to do so. 
 Requested EPA reevaluate cost effectiveness (CE) of the rule because some of the parameters for CE are not reflective of current and future conditions. The EIA projections from 2014 are off now because of gas prices and industry activity, downsizing.
 Concerned about methane permitting issue  -  OOOOa did not deal with the GHG permitting issue the way OOOO did for power plants. A more solid fix is needed. 
 Supported not including liquids unloading requirements. 
 BLM Rule
 Noted that BLM released its draft rule and expressed crossover concerns between OOOO and the BLM rule. Asked EPA to work closely with BLM. 
 Stated that analyses by EPA and BLM do not include a lot of the same exemptions. 
 Regarding crossover with the BLM leak requirements, for example, noted that the BLM rule states that if you have 2 leaks, you must change your monitoring frequency.
 Monitoring Requirements
 Duplicity of monitoring requirements that could be streamlined by having unified monitoring requirements.
 Stated their Table 26-1 compares overlap of requirements. Different closed vent system (CVS) monitoring requirements for controlling pump vs tank, also subject to leak monitoring requirements because CVS is part of the definition of `fugitive emission component'. 
 Asked that CVC be defined and that EPA look to subpart HH definition and provide consistency across rules.
 Need clarification regarding monitoring requirements for covers and thief hatches, not part of subpart HH. Also requested clarification regarding controlled vs uncontrolled emissions.
 Preferred one set monitoring requirements for simplicity.  
 Regarding well sites and CS, stated the proposed definition for fugitive emissions component (FEC) should be consistent with other definitions for equipment. Suggested language in their written comments.
 Stated dehydrators and pressure vessels are not FEC but have FEC on them (connections, etc.) and believed those types of equipment should be eliminated and the definition more reflective of what historically has been defined in equipment definitions.
 LDAR
 Stated the proposed 15 BOE exemption from leaks is helpful but generally not common for new sites because operators do not drill wells that will only achieve 15 BOE/day. Would be useful as an offramp for LDAR as a well's production declines. Suggested removing control if consistently below 15 BOE for leaks for 1 year. 
 Should exempt oil well sites from LDAR where there is no gas because economics work for methane, whereas there is little methane and gas in a strict oil well. 
 Flowback exemption for wells below 300 GOR would be an indication that it is a low gas well and the economics would be different. Should be considered exempt because so little gas is available.
 Wellsite
 Stated the definition of `well site' is problematic because it would seem to assume you take a wellhead to a central battery and aggregate to a single well site. Asked for clarity and suggested a central production site could account for an upstream central site that could be a compressor station (CS) or combination compressor station and batteries and then have a transmission CS.
 Concerned that, according to the definition of `modification', refracturing or hydraulic fracturing would be considered a modification of a wellsite. Stated that these activities do not necessarily result in increased emissions. 
 Site Survey and Plans
 Stated EPA did not give enough consideration to the cost of leak surveys, such as the cost of transportation to and from a site, training costs, costs of plan development, recordkeeping, etc.
 Stated that EPA assumed a cost of $2 to resurvey a component based on soap bubble, but that it is not apparent that use of the soap bubble test is allowed, which they advocate. 
 Asserted there is a corporate-wide plan and site-specific plan and believe there should just be one plan required based on an area. Noted that corporate-wide operations can be different within one company from one part of the country the next. 
 Stated it is unnecessary to have diagrams of sites and walking paths because sites typically are too small for this to be necessary. 
 Believed the cost estimate is high relative to the amount of methane that will be recovered. They see a long term leak rate of less than 1/10 of 1 percent.
 Because of low leak rates, an annual survey would achieve EPA's goals and make it easier for industry to manage the program, rather than having to track what has to be done quarterly, semiannually, etc.; easier to schedule an area for survey for a particular time. 
 Stated that once a site is past the initial survey, there is a diminishing return of survey; leak rate is not typically going to show marked improvement between annual and semiannual survey. 
 Expressed that requiring monitoring 30 days from startup does not make sense because during this period they are evaluating controls, etc. Recommend 180 days, ideally 1 yr. Stated 180 days is consistent with subpart VV for startup. Noted a longer period also allows for more sites to become subject to this monitoring. Opportunity to merge these sites into the existing program schedule; more cost efficient and less burdensome. Noted the burden to small firms using contract services.
 Regarding the 6 month repair requirement, API requested an extended delay of repair  -  preferably until next scheduled shutdown.
 Asked that compressor stations that add/replace a compressor without adding capacity not trigger requirements.
 Pumps
 Requested that chemical injection pumps be exempt. Stated EPA analysis; emissions below the equivalence of a low bleed pneumatic controller should be exempt; and diaphragm pumps operated less than 90 days/year should be exempt.
 Stated there needs to be a definition for `control device.' Stated the rule seems to indicate that blowers and heaters are considered controllers but stated these should be considered process devices; they are not designed for control. Preferred a definition similar to subpart HH definition so that blowers and heaters are not mistakenly considered equivalent to a flare.
 Stated costs of controlling pumps underestimated. When routing to a CD you cannot route straight from pump to CD, must route to knockout pump or SV first, otherwise the flow will overwhelm CD. In WY, for example, all are routed to a knockout device or tank first. Also must look at heat input capacity CD can handle. Will have to go back and look at CDs installed since Sept. 18 to see if CD can handle the heat input, requiring engineering analysis and additional costs. 
 Noted that a CD may already be subject to other requirements because of state permitting. 
 Noted that requirements CDs are very complicated for each device and totally different between tanks and pumps because they follow centrifugal compressor requirements.
 Stated the rule currently does not allow going to knockout or tank first.
 Stated that EPA underestimated the impacts of the rule  -  additional operating, monitoring, recordkeeping, testing, etc.; none of which were added to the cost estimate. EPA also did take into account the technical feasibility of routing nor account for when an onsite control device belongs to another party. 
 Requested a portable pump exemption. 
 Commented that there is no provision for a facility that is no longer an affected facility. 
 Recommended phasing in the rule, in part, due to the backlog of sites that will become subject retroactively to the rule.
 Recordkeeping and Reporting
 Stated the requirements for non-affected pumps to certify that they are not affected facilities and not subject to the rule does not add any value.
 Believed reporting pump control devices was also unnecessary and duplicative because they would already be reporting CDs under another state or other reporting requirement. Noted this effort was not also accounted for in the cost estimate.
 Stated CDs need further clarity because of circular referencing. Asserted, for example, that the initial PT does not appear consistent between subparts OOOO, OOOOa and the CTGs. 
 Expressed confusion over CPMS requirements, for example, SVs look like they require a PT, whereas in the CTGs it appears they may not. Stated that CPMS requirements were not intended to apply to storage tanks and are not very clear. 
 CPMS should not be required for SV because most are at well sites and no infrastructure is in place to handle CPMS plus most very small and even in subpart ZZZZ area sources do not have these requirements.
 Asked if the CEDRI system will allow them to report under a group of facilities as they are currently doing. 
 Stated that LDAR recordkeeping seems overly burdensome. Opposed having to take photos. Does the requirement mean one photo of site or one each component or one each leaking component?
 Asserted the rule seems to encourage the use of flares because as far as PT and monitoring requirements go, it would appear best for industry to install flares.
 Stated the amount of confirmation required for at pneumatic pumps and compressors falls within CPMS requirements so additional regulation is unnecessary. Do not have a full plan for pilot confirmation, would need a full monitoring plan for how to ensure accuracy measurement. 
 Regarding the requirements in section 60.18 for velocity measurement, stated that when conducting a PT, you never see maximum velocity, only a very low velocity. Therefore, suggested OOOO use a specific provision to require a design calculation instead of a velocity measurement.
 Stated they would be disappointed if the FR includes next generation compliance without a proposal. 
 Asked for exemptions for oil well completions and for separators on site for initial flowback stage on wells they typically think will not need to be separated. 
 Because of potential backlog of wells coming on line since Sept. 18, asked if wells drilled but not completed before effective date would be exempt. 
 Believed the pneumatic pump requirements for CDs and CPMS ought to be the same as for SVs and not the same as centrifugal compressors.
 Testing
 Regarding CD standards, noted the rule lists 4 standards options and wanted assurance that you can pick your compliance option, then pick your PT to meet that.
 Concerned that the PT requires a percent by weight calculation but then you need a speciated composition so you can add up VOC and need flow to calculate on a mass basis, yet mass basis was not set in the rule, only percent reduction. 
 Recommended using a carbon balance method wherein proving destruction by carbon balance, using M25a.
 Stated rule should clarify the use of design calculations which are always within a few percent of max. 
 Stated it is unclear if a FIP needs continuity if designated nonattainment. Expressed the importance of ensuring that while planning is going on the SIP does not apply just because it is designated nonattainment; extend FIP until SIP is approved.
 Stated nothing in the proposed rule accommodates synthetic minors and supported an alternative compliance option. Did not see why there should be a difference between a synthetic minor and a true minor source. 
 Requested clarity on endangered species issues. Believed statements in the preamble mean that it would not trigger federal action or ESA requirements. Prefer submitting what they did for EIS. Will an older EIS be appropriate? Would use of BLM's application for permit to drill APD be sufficient?
 Regarding case-by-case permitting at EPA discretion for site specific permit, asked for clarity regarding criteria for this. 
 Asked for a process in the FIP to allow an operator with major sites to make them minor.

Control Technique Guidelines
 Concerned with overlap between CTGs and subpart OOOO, believing some requirements appear to be different between the two that they do not believe were intended. For example, CTGs require CPMSs on SV where subpart OOOO does not. 
 Urged EPA to delay the CTGs for 6 months after subpart OOOO so that issues can be dealt with in the CTGs.
 Noted that the CTGs are guidelines for states, while a lot of states have their own regulations. Stated the preamble to the FR should remind states of the flexibility they do have. 
 Asserted that compliance assurance issues can be more of a burden than emission reduction issues. 
 Asked if states will have the flexibility to modify the CTGs equally.
 Stated that the CTGs should contain a minimum VOC threshold. 
 Requested that the OOOO provision to remove CDs at 4 tpy should be carried over to the CTGs. 
