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Lauren: Hi, I’m Lauren Parker, CEC’s oil and gas market lead. And today we’re going to sit down with CEC principal, Jim Cooper, to discuss new owner audits. Hey Jim.

Jim: Hey Lauren. Thanks for having me. Yeah, I’m the principal in the air group, but I’m also the office lead for the Cleveland office and, and have quite a bit of experience in oil and gas. I’ve done a lot of regulatory affairs work with a lot of trade associations across the country, federal and state. Hopefully, we can kind of shed some light on an EPA-sponsored program that is out there that’s somewhat of a benefit or a significant benefit to upstream oil and gas operators.

Lauren: Can you give me an overview and a background of what the program is?

Jim: Yeah, so it’s the, the EPA Oil and Natural Gas New Owner Audit Program. It was finalized back in March of 2019, and basically what it is, it’s a voluntary self-audit on the tank vapor control systems for any newly acquired oil and gas assets. And what it involves is the correction of any design or operational issues discovered during that audit. Of course, there’s a kind of a predetermined set, a set of audit criteria and must be approved by EPA. And of course, there’s terms and timeframes that must be adhered to in order to be able to recognize the benefits of the program.

Lauren: And is everyone eligible or are there specific things that make a person eligible for the program or not?

Jim: Currently, the program is only available for upstream oil and gas companies and operations. I could see in the future midstream assets being rolled into this, or maybe they’re doing, they’ll do a separate program for midstream assets, but, you know, as of right now, it’s just set up for upstream oil and gas production facilities. And I think why that is, when you’re looking at acquisitions and asset sales, the number of facilities involved in a region or in a basin or in an area on the production side, it’s, it’ll be a much higher volume than if you were to kind of look comparatively at a midstream facility. So, say in an area you might have 10 or 12 midstream facilities, where in that same area, you might have 150 upstream, you know, well pads. So, I think they kind of, took the big bite first with the, you know, rolling the production locations into this. And you know, maybe later on down the road, they’ll roll the midstream in. You know, there’s more moving parts in the midstream side, but as far as just a sheer volume of facilities in an area, there’s many more production locations. So, I think that’s kind of why they set it up this way to begin with.

Lauren: That makes sense. Now is any EMP company eligible or are there certain criteria or certain number of assets they need to own or anything specific like that, or anyone can apply for it?

Jim: No, there’s nothing like that. It’s for a company that has acquired new oil and gas upstream assets, and that’s really, it, there’s no other kind of qualifying criteria for it.

Lauren: When thinking about the program, why is the EPA doing it? What’s, what’s the benefit for EPA?

Jim: The EPA wants they want reduced emissions, right? So, that’s what their ultimate goal is. And prior to an asset sale or an acquisition, there’s a, there’s a really good chance that those facilities were sitting there, maybe just doing the bare minimum, maybe the compliance side of things, wasn’t really under the same type of scrutiny under the previous owner, that it would be under this program when the new owner kind of enrolls in it. So EPA wants less pollution, and this is a way to kind of facilitate that quickly, and without all the red tape, that’s, you know, typically involved in permitting and, you know, EPA driven compliance efforts and, you know, that stuff cost EPA money and it costs EPA resources. So they have, you know, folks that have to go
out in the field and do these things. So, EPA can kind of pass those inspection costs off onto the owneroperator and still get the desired result, which is reduced emissions.

Lauren: And so the cost of doing the inspections is pushed onto the operator. So, what’s the benefit to the operator?

Jim: Well, the operator is, as long as the terms and conditions and the timeframes are adhered to, they’re going to receive compliance forgiveness and be exempt from any financial penalties that are typically associated with the types of violations they might find. So even though companies, like they go through a fairly exhaustive due diligence process prior to an acquisition, when you’re talking potentially hundreds of facilities, it’s not hard for something, especially something air quality related to kind of slip through the cracks. There’s a lot of reporting and record-keeping, kind of I’s to be dotted, T’s to be crossed, that can kind of, it can be missed during your typical acquisition due diligence activities. So, it’s sort of a get-out-of-jail-free card so to
speak for the operator.

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Lauren: So, can you go over some of the components that are involved in the audit?

Jim: Yeah, I won’t get too far in the weeds. I I’ll touch on a few of the, kind of the high points and, and we’ll go from there. But the, you know, the owner, or the owner’s representative once, you know, everything is kind of finalized, the agreement is there, it’s in place, there’s a lot of paperwork involved up front. So you’re going to have to prepare and submit audit instruments. This includes your checklist and your protocols; the checklists are what you’re going to do, and the protocols are how you’re going to do them. So you’re also going to have to submit a complete vapor control system engineering analysis, which includes, you know, tank calculations, open-loop modeling guidelines, or closed-loop design guidelines, whichever one applies to that particular facility or facilities and any sort of standard operating procedures for calculations or the field inspection component of what you’re doing.

So, there’s a lot of kind of, you know, outline type things. This is what we’re going to do. This is how we’re going to do it. And there’s a desktop kind of review and an engineering analysis component as well. So, in those, all, all of that paperwork component once the once you, everything is finalized, that audit agreement is finalized with EPA. The owner-operator has 60 days to submit that to EPA for their review. And then once EPA gets those documents in hand, they have 45 days to review those and get back to the owner-operator with any comments or questions that they have. And once the owner-operator gets those comments back from EPA, they have another 30 days to make any corrections that are necessary. And once those, and once all that’s done, once the comments are done, all of those audit instruments are finalized and everyone’s kind of agrees upon those — and they can change — but once that first level of finalization occurs, that’s when kind of the real work sort of starts, you’re going to start your desktop review of your permits, making sure that you’re compliant with all the permit requirements at the state level or at the federal level. And you’re going to, if there’s any gas or liquid sampling that needs to be done for the emissions models, you’re going to start to do that stuff at this time. Your leak surveys can be done at this time, which is going to be a big, a big part of the field component of this is going out and making sure these vapor control systems are doing what they’re designed to do and making sure there aren’t any flaws anywhere. And your corrective actions, if you find anything that’s considered a violation under the agreement, you’re going to have to fix that. Verification that it has been fixed will be done. And there’s a pretty significant reporting component of it as well. Also, there’s, you know, after the desktop review is done, after the field inspections are done, data’s going to need to be summarized. And that reporting component, depending on how long the audit runs, there, you have to, you’re required to do semi-annual and annual reports. So reporting can kind of be an ongoing thing.

Lauren: It sounds like definitely something where you would want to have a person like you, who knows the process involved. There’s a lot of different moving parts, it sounds like. One thing that you mentioned that I’m not familiar with, I’m not sure if the listeners would be, is open-loop and closed-loop guidelines. Can you explain a little bit about what the difference from those things are?

Jim: Yeah, and to kind of put a finer point on what you said, there are a lot of moving parts and there are a lot of kind of confusing things about this. So typically, what you’re going to have, you’ll have third-party consultants, you know, with this, there has to be a third-party verification, so they don’t just turn the owneroperator loose and have them do it all themselves. So there has to be some sort of verification by, you know, a qualified third party. So there is that, there’s also legal components to it. So, there’s, you know, typically you’re going to have either outside counsel or internal counsel or both that are going to be involved in the process of developing the agreement with EPA. So, there’s, it’s, there’s going to be several people involved and a lot of moving parts, like you said. But I think probably the best way to explain the difference between the open-loop model and guideline and the closed-loop design guideline is to explain the difference between the open-loop vapor control system and a closed-loop vapor control system.

So what this is, you’re trying to control the emissions in the tanks through some sort of a — you’re either have a vapor recovery unit, or maybe you have a closed-vent system that’s directing those overheads to a flare or a combustor or something like that. So the closed-loop systems are typically more intuitive and they’re, they’re kind of driven by system feedback. So, when certain pressures are reached, maybe that triggers the VRU to kick on and pull vapors, those overhead vapors off the tank so you don’t exceed that leak point. Or it could possibly even change part of the process, so you’d never reach that leak point and have an
issue where you have vapors or emissions coming out of the thief hatches or the PRVs. So the closed-loop system is — a lot, more going on there. 

It’s a lot more intuitive. And so the open-loop system, conversely, is you don’t have all of that feedback in the system. It’s not very intuitive, really. You just have a closed-vent system that’s, as you generate overheads in those tanks, it’s gonna direct and funnel those overhead emissions to some sort of control device. And that’s typically going to be a combustor or flare or something like that. So, they’re not intuitive, they’re not feedback driven. And that’s, you know, it just simply controls the emissions that the tanks generate by routing it to some sort of control device. So, this is pretty typical. You see that a lot more than you see the closed-loop systems. Now, I think, as far as, you know, a strict control device on a tank, I don’t know that too many people use the VRUs anymore. There are cases where they use them out there.

A lot of times they will use the VRUs more off of a separator or something like that to kind of, you know, salvage some of the gas that might normally be wasted and get it back into the system. But for controls, I think the, probably the majority of what you see out there are the open-loop systems. And, you know, the limiting factor there on the open-loop system is you just want to make sure that your flare and your combustor is designed to be able to handle whatever that potential peak instantaneous flow rate is coming off those tanks. And then you should be good. So, that’s hopefully, that wasn’t too confusing, but that’s, that’s kind of the difference in those two things.

Lauren: Well, so is that something that whenever you’re doing the field audit work, you know, if for instance, they have an open-loop system and perhaps the flare isn’t sized appropriately for what’s coming out, that’s something that we would identify during our field investigation?

Jim: Yeah and we can, you know, what you might see in a situation like that is a smoking flare, you know, it might be a lot of black smoke coming out of the flare because it’s being overwhelmed or maybe even it’s getting liquids in it or something like that. So that could be caught. It could also be caught in the desktop review, as you’re determining that, you know, potential peak instantaneous flow rate is kind of how you’re, you know, when you’re going to do this design evaluation or somebody is going to do it you know, maybe even prior to going out in the field. So you may catch something like that before you even go out.

Lauren: So whenever corrective actions are identified, what are the owner-operators’ obligations to take care of those? And is there a timeframe that they have to take care of those?

Jim: So, you could find deficiencies or a need for corrective action in really two different ways. And one of them could be during the desktop portion or the engineering evaluation, you could find a situation where your flare is not designed correctly to be able to handle that flow rate. So that could be something that you find before you even get out in the field. So there’s that, there’s also, as I mentioned, you know, during the field survey, you could find leaking components, you could find a thief hatch that’s, that’s leaking because the seals are dry and cracked, and they haven’t been changed at the appropriate interval or something like that. So, you know, the compliance deviations can be found, you know, at, you know, in the office doing a desktop review or out in the field. So, either way when you find them, owner-operator has 180 days to fix those, to take the corrective action and also take steps to ensure that it doesn’t happen again.

And you have to kind of satisfy that component for EPA as well. So it’s not just fix it and walk away. You have to put some sort of plan in place to see that it, that it actually doesn’t happen again. So corrective actions, they can involve simply just modifications to maintenance procedures. Like I mentioned, with the seal and with the thief hatch, you know, maybe they’re just, they need to do that more frequently or maintenance inspections need to happen more frequently. Maybe bees are building a nest in the, in the pressure relief valve causing it to stick open or something like that. So, it could be, you know, there maybe there’s nothing else really wrong other than just you need to ramp up maintenance procedures a little bit, so, and kind of change how you’re doing the maintenance and that maybe that fixes it.

It can also, a corrective action could also involve changing the operating conditions of the facility, kind of to decrease that potential peak instantaneous flow rate we talked about earlier on the open-loop design to make sure your flare is not being overwhelmed. Or it could be changing operating conditions to ensure that the tank pressures aren’t reaching that leak point that you would determine for the closed-loop systems. Worst case scenario, it could mean modifying or possibly even replacing your vapor control systems on your, on your tank. So, and once I — that’s going to be your worst case scenario, I don’t think you’re going to see that that very often, but it’s definitely something that’s, that’s a possibility and may have to be considered depending on what’s going on. Once the changes are completed, once everything’s done, you’re going to have to go out and you’re gonna have to verify again, through OGI, leak detection, to make sure that, you know, the changes you’ve made, aren’t resulting in leaks. 

And you’re gonna have to do that, that leak detection verification on these systems during normal operation where things are just kind of sitting there. And then you’re also going to have to follow that up with an OGI inspection during an active dumping event from a separator. So you’re, while you’re actually physically dumping liquids from separators in the tanks, you’re going to have to do that. So, it’s kind of a two-pronged leak detection kind of verification of that. So there’s one other thing on this that’s anything outside of these vapor control systems that you find, it’s, it’s really specific to that, but they don’t kind of, they don’t really let you off the hook completely for other potential violations that you might find while you’re out there. So, if you’re ever out there and you see something that’s a violation or a potential violation, that’s outside of the scope of this program, you’re still required to fix it. So, and they, for whatever reason, EPA gives you 60 days to fix those. So, where you have 180 days to fix the kind of those violations that are within the purview of this program, you have to fix anything outside of this program that you find, yet you only have 60 days to fix those. So a little bit of a kind of a curve ball, they throw you there.

Lauren: So, for example, if it is like a maintenance thing where you just need to go out and provide more frequent maintenance inspections and maintenance, that’s something that would be in the written plan that would get submitted to EPA. And they would have time to say, yes, we agree that that is the appropriate way to fix this, so put that plan in place. So, before you do anything again, they’re agreeing with what, what is being said and authorizing that to be the corrective action.

Jim: Yeah, absolutely. There’s, there’s a process at the end of this where EPA is going to put their stamp of approval on it. And not only for that, but for the other components of the program too. You know, have you adhered to everything that they’ve said, and do they agree with your fixes? And so yes, absolutely. You’re going to report that, like I said, in the, in the reporting with the reporting component of this, and then EPA is going to have their chance to review and come back and sit down at the table and make decisions on whether that’s going to be sufficient or not. That’s where, that’s where the lawyers get involved.

Lauren: After an owner-operator acquires the assets, how long do they have to enroll in the program before they kind of like miss the window of a new owner audit?

Jim: Yeah, they, they have nine months. So once, once the asset sale is final, once the assets have actually changed hands, whenever that date of acquisition is, you have nine months to contact EPA. You know, it doesn’t really it doesn’t really give a good description of what that is, but you have to inform EPA of your intent within nine months. And then you’ll sit down at the table with them and start to hammer out the details of the agreement after that. So, you know, that’s, that’s not nine months to get the final agreed upon set of terms. That’s just nine months to make that notification. And then you start working, working on those details with EPA, what the audit is actually going to look like and what it’s going to entail. So there is a little flexibility, I would say that it’s probably safe to say that every audit is going to look a little different.

They’re going to have, each owner-operator is going to have it set up just a little bit different with EPA. So there is some room to, to kind of make it unique and to fit your, to fit your situation. So, the basic components will be the same, but I think there, you know, there can be a little bit of wiggle room for making it kind of fit each individual owner-operator. So, you set it up, you contact them within nine months. You say, we have 150 facilities that we want included in this. Well, you get your audit agreement finalized. You start to work on all of the, kind of, all the other parts of the audit, the desktop review and the field portion of it. Well then, all of a sudden, say you acquire another 50 sites somewhere that were not included in the original audit. EPA does provide a mechanism to include those in the audit. You just have to notify EPA in writing within three months of the acquisition of those new of those new sites. And you can include those in your original audit. You’re just going to have to provide information. You’re gonna have to list them out, what they are, where they’re at, things like that. So, but there is a provision to, if you there’s another acquisition, you can actually want those in with, with the original ones.

Lauren: You want to hit on just a couple highlights for us, Jim, that kind of can stick in people’s minds as they think forward to any future projects they might have?

Jim: I’ll say this, I think there’s a lot of, there’s a lot of assets changing hands these days, and there’s a lot of acquisitions happening and there’s a lot of people acquiring oil and gas assets out there that that aren’t necessarily oil and gas companies. There’s a lot of financial institutions. There’s a lot of investor groups that are acquiring oil and gas assets that probably aren’t even aware that this, this program is out there. There are definite benefits to using this program. And I think probably the biggest drawback, is just a lot of people don’t know that it’s out there and that they can use it. There’s also certain states have a state version of this kind of a compliance forgiveness that’s, you know, involved with voluntary reporting of violations and fixing
them and things like that. But I think it’s definitely something that a company should pay attention to with the rate that assets are changing hands these days and the way companies are selling off and bankruptcies and things like that.

A lot of these, a lot of these upstream oil and gas assets are moving around and, you know, I’ve seen fines in the million dollar range, so it’s nothing to sneeze at. So I think it’s something that owner-operators should definitely consider beyond their normal due diligence that they do during an acquisition. I think this is definitely has its benefits.

Lauren: Well Jim, thanks for taking the time to chat with us today. If you want more information on this topic, please email Jim at JCooper@cecinc.com. And if you are interested in any general information on CEC’s oil and gas services and experience, feel free to email me, Lauren Parker at LRParker@cecinc.com. 

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