DRAFT

MEMORANDUM

Date: October 12, 2011

Subject: Summary of discussion from the September 21, 2011, meeting between 

the American Petroleum Institute and the Environmental Protection 

Agency

From: Heather Brown, EC/R Incorporated

Bill Huang, EC/R Incorporated

To: Bruce Moore, EPA/OAQPS/SPPD/FIG

I. PURPOSE

This memorandum summarizes the September 21, 2011 meeting between the 

Environmental Protection Agency (EPA) and industry representatives from the American 

Petroleum Institute (API). The purpose of this meeting was to listen to comments and concerns 

from the API regarding the August 23, 2011, Oil and Natural Gas Sector proposal. 

II. DATE

The meeting took place from 10:00 am until3:00 pm on September 21, 2011 at the 

Research Triangle Park, NC, campus of the EPA. 

III. ATTENDEES

The following individuals attended the meeting:

Industry Representatives

British Petroleum: Jeffrey Adams

Dana Wood

Chesapeake: Grover Campbell

Shell George Deeley

TGB Rob Ferry

Chevron Clay Freeberg

ConocoPhillips Clint Gill

Devon Joe Leonard

ExxonMobile Tom Monahan 

American Petroleum Institute Matt Todd

Marathon Jenny Yang
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U. S. Environmental Protection Agency 

Office of Air Quality Planning and Standards Bruce Moore

Greg Nizich

Alex MacPherson

Office of Atmospheric Programs Suzanne Waltzer (by telephone)

EC/R Incorporated

Heather Brown

Bill Huang

IV. SUMMARY OF DISCUSSION

The following is a summary of the discussion during the meeting. The summary has been 

arranged by topic and is not necessarily presented in the order in which it was discussed. 

General

Bruce Moore went over the ground rules for the meeting with respect to time between proposal 

and promulgation. He is limited to what he can say, and could only answer questions with factual 

information and provide clarifications. 

API stated that they appreciated EPA for not including for regulation units such as amine treaters 

and deliquifying. One of API’s main concerns is applying control technology on a nationwide 

rule, and reiterated the need for flexibility in the rule. 

API stated that they liked the structure of the oil and gas sector new source performance 

standards (NSPS), subpart OOOO, because the new subsections will help with future 

compliance, but stated that cross references to the oil and natural gas production national 

emission standards for hazardous air pollutants (NESHAP), subpart HH, are always difficult to 

follow. In addition, the changes to subparts HH and HHH (the natural gas transmission and 

storage NESHAP) are hard to follow. 

Extension of Comment Deadline

API noted that they have submitted an extension request for the comment period and in turn, the

promulgation date. API stated that there a lots of details to evaluate, and wanted to make sure 

both API and EPA have enough time, and to ensure it is done right the first time. In addition, 

API stated they won’t have time to address solicited comments without an extension. 

EPA stated that they are addressing the comment extension with OGC, but says it’s up to the 

decision makers. If they do that they will have to push back the promulgation date as well. 
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Additionally, API mentioned that the information collection request (ICR) comment deadline is 

tomorrow and affects their time to address comments. 

New definitions

API expressed concern that EPA had preempted section 60. 15 of the General Provisions, which 

defines “reconstruction. ” API was concerned that the new definition of modification includes 

VOC and natural gas. API stated that a threshold is needed for what VOC is to distinguish coal 

bed methane (CBM) and low VOC content. According to API, not all recompletions increase 

emissions, sometimes referred to as reenergizers or workovers. 

Another concern was EPA’s defining of the commence construction date of a relocated 

compressor as the date the compressor is installed. API stated that relocation has never been 

defined as a modification for NSPS and NESHAP. API suggested that the manufacturer date

should be used as the commence construction date. EPA suggested API provide alternative 

language in comments. 

API also discussed the definition of pieces of equipment specifically as an affected source (e. g. , 

pneumatic controller, compressor). According to API, documentation will be a problem for so 

many individual pieces of equipment. API indicated that State minor new source review (NSR)

programs will kick in if any NSPS or NESHAP apply to a piece of equipment and the emission 

thresholds go away if NSPS or NESHAP apply. This will force a site to get a new permit every 

time a new pneumatic controller is installed. API stated that this would be very burdensome to 

States and industry. API also stated that this is an issue for completion permitting. 

Compliance Assurance

API was concerned about the detailed monitoring, testing, notifications, recordkeeping, etc. 

associated with the compliance demonstrations. API noted that much of their industry is located 

at remote, unmanned sites with no electricity. API stated that continuous parameter monitoring 

systems (CPMS) for tanks are issue where subpart OOOO cross referenced subpart HH. API 

stated the CPMS requirements were written for HAP not VOC, and HAP rules were written for 

major HAP sources therefore, the reason for language is different. API stated that they believe 

that CPMS were intended for major sources because non major sources are usually without 

power and communications infrastructure. 

Notifications 

API stated that they generally liked the requirements for pneumatic controllers. However, API 

stated that advanced notification for so much equipment is problematic, and needs to be more 

streamlined. API suggested only submitting notification at first required report. API also 
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suggested allowing for periodic reporting at the 1-year anniversary of installation. API expressed 

some confusion about how to combine reports. They submit title V reports for major sources. 

Some reporting required annually but not required on anniversary. API suggested operators

report activity over a period of time and report all equipment over some geographic area. API 

asked what the value is of the information in reports. API suggested a 60-day buffer between the 

end of the reporting period and the due date of the periodic report. 

Low VOC Threshold

API suggested that EPA set a low VOC threshold for applicability to subpart OOOO. According 

to API, VOC less that 5 percent by weight would not be worth controlling (e. g. , dry shale gas, 

coal bed methane (CBM)). API suggested EPA evaluate where the cost impact reaches the cost 

effectiveness threshold ($/ton). 

Compliance Dates 

API pointed out some confusion relative to the compliance dates and the effective date. EPA 

stated that had already been pointed out internally. 

API stated that some clarification was necessary with respect to the compliance date. API 

suggested that compliance be required 60 days from date of publication of the final rule in the 

Federal Register. API pointed out that equipment is not always available. As an example, API 

stated that every new and modified tank required to be controlled under the rule may need one or 

more combustor for a tank. API stated that combustor certification is not currently available. At 

this time, no manufacturer does this and there are not enough available. EPA suggested that, to 

support their argument, API get suppliers to submit how long it would take them to ramp up to 

meet demand. 

Costs

API stated that EPA appeared to have done a good job calculating the rule cost impacts for the 

pieces included. However, API stated that there are hidden costs that need to be considered in the 

cost calculations. For example, EPA did not include costs for vapor recovery unit piping, and 

costs associated with increased pad size for a combustor (these are not minor costs). For 

unanticipated, but necessary costs, EPA suggested API include in their comments, things we 

haven’t included. 

Completions

API asked how EPA intends to address completions offshore. API stated that they had just 

started to think about this, and did not believe EPA considered offshore implications. 
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API expressed their concern about the lack of availability of completion equipment and 

experienced operators due to the shortage caused by the Wyoming Department of Environmental 

Quality (DEQ) best available control technology (BACT) requirements. API was concerned 

about being rushed to get this equipment and that meeting specifications for this mandatory, 

nationwide rule could lead to unsafe conditions, which would cause job losses, and safety risks. 

In addition, API stated that it will take significant time to deal with API standards and pressure 

vessel codes. API stressed that inexperienced operators lack the knowledge and experience to 

handle issues within the industry. API also stated that the Natural Gas STAR Program is 

voluntary so operators were properly trained. According to API, Wyoming DEQ provided this 

sort of time for compliance. 

API was also concerned about prescribing specific equipment during completions (for example, 

requiring a sand trap). API stated that some equipment required may not be necessary or 

necessary at all times during the completion. EPA suggested API provide suggestions on a better 

way to do this. API also requested that different techniques, such as the reverse circulation 

technique, need to be allowed. EPA mentioned Colorado’s thresholds for completions and asked 

if API knew where they came from. Knowing how these threshold were derived would help to be 

able to establish threshold. API also mentioned the low VOC threshold for CBM. API stated that 

they would like flexibility to develop techniques to reduce VOC emissions down the road. 

API wanted more flexibility to flare a vent, but felt that the regulatory text doesn’t address the 

issue. API fears the reporting/recordkeeping requirements will be used as enforcement against 

them. API stated that there are operational and safety issues. According to API, it is hard to 

gauge well production and they don’t always have the equipment on site available, or gathering 

lines for permits etc. API stated that third party gathering could take down gathering the lines. 

API stated that there were BLM issues as well and other costs we didn’t consider. 

API also had a concern about pipeline pressure issues and when to route to the sales line. API did 

not like the words “as soon as practicable” because enforcement might judge it differently (i. e. ,

completion could be viewed as the same thing as construction activity). EPA challenged them to 

add what’s missing from the rule. API responded that they have sent out industry surveys before 

and that line pressure isn’t something they currently measure and record. EPA asked how they 

normally decide to vent or recover. API responded it is mostly a question of trial and error and 

experienced judgment call. API stated that opportunities for venting need to be provided when 

when adding nitrogen or carbon dioxide (energized completions) and if there is hydrate 

formation, which plugs pipeline wellhead equipment, completion equipment, etc. 

API pointed out that the language for the notification 30 days before the completion in the 

preamble does not equal the rule language. EPA clarified that it should be 30 days before, in 

order to give enforcement an idea of what you are doing. API stated that with Subpart A, a 30-
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day notification, plus a 30-day notification before commencement is overkill and would overload 

EPA with 6 notifications on every completion. EPA asked for a streamlined notification 

suggestion. It is not EPA’s intent to overly burden industry and enforcement. 

API stated that they needed clarification on the definition of gas well. The term “mouth” of the 

(gas) well was not clear and is not a term that industry typically uses. API also requested 

clarification on the definition of a gas well. API said the difficulty is there is no predictability in 

this industry and frequently you don’t know what kind of well it will be until completion. As an 

example, API described a situation with dual completions (i. e. , two strings in one well). API 

suggested using Subpart W for consistency. They stated that how wells are permitted locally 

would be easiest but it is not uniform from State to State. 

API also stated that there is a huge overestimation of the number of recompletions. According to 

API, it should be 0. 1%, not 10%. EPA stated that they expected this from a lot of commenters. 

API also stated that the costs are much greater and the amount of gas recovered is incorrect. API 

stated that they could provide actual amounts/bills and a “case study. ”

API asked if a well is fracked once, is it always considered a fracked well. API stated that they 

believed there would be some problems with definitions down the road for enforcement. API 

was concerned that once something is fracked that every subsequent action will be considered 

fracking, even though it may not actually be (i. e. other completions that may be considered a 

modification of fracking). EPA stated that they are looking at any action immediately following 

the fracture, specifically a good word that explicitly states a workover two years down the road is 

not subject to the provisions. API suggested that the language say “when fracking is involved. ”

API also asked about the timing of the requirements for completions. API was concerned about 

what would happen if a well that exists before August 23, 2011 is completed doesn’t have to 

comply until promulgation. Further, API stated that the recordkeeping text is unclear, and the 

intent is not explicit. API said the industry is panicking, because they read this as immediate 

recordkeeping and compliance. API requested EPA publish a letter or something that can be 

done to calm everyone down. EPA responded that attorneys are nervous about putting something 

in text, but EPA says it is going to be changed without some writing. EPA said that they are 

unaware of a short-term solution that could be done to make this better. API stated that there are 

some requirements that as the rule reads now, apply between proposal and promulgation. 

Storage Tanks

API questioned the language in the preamble with respect to storage tanks where EPA stated that 

“...absent flash emissions the emission approach zero.... ” According to API, “dead oil” tanks 

have no emissions but are regulated under the proposed rule. API suggested having a throughput 
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or emissions threshold for tanks. API pointed out that these thresholds are usually being 

calculated for state requirements. 

API stated that they’d inferred from the preamble and rule language that EPA is intending to 

regulate condensate and crude oil tanks, that are stationary and in the production segment. API 

then asked whether the sector includes the liquid distribution pipeline and if it does, it shouldn’t. 

API also pointed out that in their opinion, the change in the tank definition removed the point of 

custody transfer and now points to the OLD MACT, but OLD MACT points to subpart HH. 

API also pointed out that the storage tank definition included a 10-tpy cutoff. EPA responded 

that this was an error. 

API noted that the throughput and cutoffs apply to crude oil and condensate, but asked if there is 

a diesel rule and is EPA intending to regulate other fluids. According to API, a tpy emission limit 

for storage tanks would take care of other types of fluids. EPA responded that they did not 

envision covering diesel tanks. 

API then asked whether EPA intended to cover temporary tanks or just stationary tanks. EPA 

responded that the tank would probably have to be there for a year to be stationary. EPA 

suggested that API ask this question in its comments and propose a solution. 

API noted that the throughput threshold is a problem. According to API, capacity and vapor 

pressure cutoffs were more appropriate. Flash tanks would not fall under capacity and vapor 

pressure cutoffs. According to API, if the storage tank does not have flash emissions then why 

not have vapor pressure and capacity cutoffs. As a result, cost effectiveness for very low emitting 

storage tanks would approach infinity. Another possibility would be to have an Reid vapor 

pressure (RVP) test. This would make complying with the rule simpler. 

API stated that issues with throughput cutoffs result from having a high original production rate

and then a production rate decline. Another issue is that with an annual throughput cutoff, 

industry would need a year to gather the data. Therefore, API recommended using sales volume 

as a measure of throughput. Additionally, API pointed out that a couple of States already have 

cutoffs. 

API asked why EPA chose to use the emission factors to determine the throughput from 

emissions. API TCEQ ranked methods for calculating emissions from flash tanks and the East 

Texas study used by EPA was not high on the list. According to API, an emission cutoff of 10 

tpy is appropriate. 

API discussed the Wyoming DEQ BACT policy, which allows potential emissions to be 

calculated by using a 30-day throughput times a decline factor. Wyoming also allows 60 days to 
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install controls and allows controls to be removed after decline the emission rate is less than 6 to 

8 tpy and below specific throughput. The usage of tank could be intermittent. API also suggested 

separate cutoff for larger capacity tanks with throughput less than a specified gallons/year. An 

example would be storage tanks designed to accommodate unloading liquid from well. The 

throughput only cutoff would be a disincentive to replace tanks that may be old and in need of 

replacement. 

API asked how well populations were calculated. API also asked about the 500 ppm leak 

definition for tank roof fittings. API stated that they could manufacturer data showing that 

Enardo valves couldn’t meet the 500 ppm leak definition. According to API, Enardos valves are

designed to have an inherent leak rate that would be greater than 500 ppm. API recommended 

EPA use the work practices they provided a few months ago. 

API stated they would like an option for floating roofs for non-flashing tanks. They stated that 

when being extended to black oil tanks, floating roofs should be allowed. 

In the cost analysis API stated there are line items in such a project that need to be accounted for 

to get the full cost. API stated that new tanks were more expensive to install for valves and 

fittings and that EPA needs to account for tanks that have to install valves and fittings to comply 

at a later date. API stated that they need time to install controls once they become subject. As an 

example, API stated a potential solution, would be to give the industry time to determine what 

production is, and time to determine the decline factor. 

EPA asked API how they would like to see storage tanks rule designed. API recommended using 

the Wyoming DEQ program as a model for throughput and emissions threshold. The operator 

would determine the decline factor in the field. Since the decline factor varies across the country; 

EPA could use national average or allow to be calculated in field. EPA stated that they would 

take a look at the Wyoming program again. API stated that they would also review the program. 

API reiterated their concerns with changes in subpart HH that now would be required and is 

cross referenced from subpart OOOO, such as MRR issues and General Provisions. API also 

mentioned that the NSPS doesn’t refer to the certified equipment allowance in subpart HH. API 

also reiterated the remoteness of sites as issues to compliance. API suggested using a deminimus 

HAP level or a cutoff similar to the “in organic HAP service. ” 

API mentioned the NESHAP revisions regarding the MACT floor. API was concerned about the 

tanks that were used for the floor determination and requested EPA submit the legacy docket 

memo regarding the MACT floor. 
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Risk Assessment

API reviewed sites with risks greater than 100 in a million. API pointed out a few sources that 

may be erroneous and would drive the risks below 100 in a million. One of the sources was an 

area source. The other source was the Hawkins Gas Plant. The national emissions inventory 

(NEI) says there are 5 glycol dehydration units at Hawkins, but in fact there have only been 

3 dehydration units for more than 10 years, and one has a 2 MMscf/day throughput and the other 

two are permitted below 1 tpy benzene. Therefore the Hawkins plant is not represented correctly 

in the NEI. There is also a spreadsheet error making the risks greater than 100 in a million. 

API also asked why does the equation for the calculation of the MACT floor for dehydration 

units go to zero, why not stop at the floor. API also asked if the compliance level of 1 tpy goes 

away if the risk is less than 100 in a million. 

Pneumatic Controllers

API stated they had no issue with the requirements for low and no bleed pneumatic controllers. 

However, API stated that they were concerned with pneumatics being defined as an affected 

facility, which causes permitting issues with state NSR. API suggested a couple of fixes: (1) If it 

is an air driven pneumatic controller, it is not defined as a facility because there are no VOC

emissions. Instead, define it as a gas driven pneumatic and (2) recognizing in the preamble that 

there is a permitting problem, and discuss the permitting issue is not the intent. 

API again expressed their concerns with the use of natural gas versus VOC and that natural gas 

shouldn’t be a surrogate. For example, CBM has no VOC. API stated that the gas definition in 

KKK doesn’t work anymore because CBM can’t point there for pneumatics. 

API stated that there is no value added from annual reporting, because they would just resubmit 

the same report with a different date every year. EPA clarified that wasn’t the intent. EPA 

intended for industry to submit an annual report for new units in the past year. API stated that 

they misunderstood, it may not be in the regulatory text, but it is stated in the preamble. API also 

suggested using a concept for subpart OOOO that is similar to subpart JJJJ which does not 

require reporting for certified engines. 

API stated that there needs to be a better definition of gas processing plant. Remote plants do not 

have electricity. API stated that there are questions as to whether dew point depression skids (i. 

e. , JT skid) is a gas plant. Some States think they are NGPP but most don’t. EPA asked API to 

suggest a new definition in their comments. API stated that the subpart KKK definition would 

work only if you specify liquefied petroleum gas (LPG) or natural gas liquids (NGL). 
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LDAR

API was concerned with the new leak definition for existing gas plants subject to subpart HH, 

because former non-leakers would suddenly need to repair. This is an issue for the liquids area of 

plant. API stated that the compliance time under subpart HH for existing facilities needs to be 

extended in order to get them to comply. 

API was also concerned that subpart OOOO requires modifications to pull in more components 

that were existing, since it doesn’t take that much of a cost to trigger the definition of 

reconstruction, due to the age of the plants. API would prefer to keep the leak definition of 

10,000 ppm for existing facilities, but if that isn’t possible, then API stated industry would 

require a later compliance date. 

API stated that the terms defined in subpart OOOO are confusing. As an example, API stated 

that the term “equipment” and the term “affected source” don’t work together. API then asked 

about how the stay on subpart VVa affects this proposed rule. EPA responded that subpart 

OOOO points to the procedures in VVa, but the affected facilities are not subject to subpart VVa. 

API pointed out that certain provisions, such as capital expenditure and connectors, are stayed. 

According to API, the LDAR program for connectors is problematic, because it will bring in a 

lot of other components. Adding connectors changes the number of components by four times. 

Compressors

API was concerned about the relocation of compressors, since they tend to relocate quite often. 

They explained that rental companies come in to swap out compressors frequently. API asked 

whether the rental companies should be responsible for the recordkeeping