Transcript of “Stayin’ Alive: The Last Days of Stripper Wells in the Ohio River Valley” Conference Call with Ted Boettner

Jan 07, 2022

On January 5, The Capitol Forum hosted a conference call with Ted Boettner, Senior Researcher at the Ohio River Valley Institute (ORVI) and author of ORVI’s most recent report, “Stayin’ Alive: The Last Days of Stripper Wells in the Ohio River Valley.” The full transcript, which has been modified slightly for accuracy, can be found below.

MR. DANIEL SHERWOOD: Good morning, all. And apologies for the slightly delayed beginning here. But welcome. We’re glad you’re here. Thank you for joining The Capitol Forum’s conference call today. We’re discussing the Ohio River Valley Institute’s recent report “Stayin’ Alive: The Last Days of Stripper Wells in the Ohio River Valley”.

I’m Daniel Sherwood. I’m Senior Energy Correspondent here at The Capitol Forum. And I’m joined today by ORVI’s Ted Boettner. And thank you for joining us, Ted. We are very happy to have you.

For those of you dialing in, and reading this later, Ted plays a central role in shaping the policy landscape as it relates to the energy transition. His expertise in workforce and economic development, sustainability, and energy give him an edge in understanding the nuances of the natural gas industry in Appalachia. Today, we will review Ted’s report on stripper wells discussing their role and scale in the region, bonding coverage subsidies and their underlying economics. For those of you who follow Diversified Energy, we will also be mentioning its operations, of course, as they are the largest owner of stripper wells in the country.

A quick piece of housekeeping before we get underway. For the first 20 minutes or so of the call, I’ll interview Ted and we’ll leave some time for questions from the audience. If you do have questions, please email them to That’s and capitol is spelled with an “o”.

I’m very excited to hear all that Ted has to share. We’ve got a big report to cover, so let’s get started. Happy New Year! Welcome, Ted.

MR. TED BOETTNER: Hey, thanks for having me, Daniel. Happy New Year to you!

MR. DANIEL SHERWOOD: Absolutely. Glad to connect. Now, let’s just start out real basic and everybody can clear out the cobwebs from the holiday and New Year, and we can just do some definitions for starters. Can we just define – what is a stripper well? And why is it that you gave it such a thorough focus here for this report?

MR. TED BOETTNER: Yeah, no problem at all. Generally, stripper wells are low volume producing oil and gas wells. They usually operate at the edge of profitability. Now, the federal

government, EIA, and the IRS define a stripper well as a well that produces less than 15 barrels of oil or 90,000 cubic feet of gas per day. So, anything less than 15 barrels of oil equivalent. While the Interstate Oil and Gas Compact Commission, which readers might look at like a quasi-government agency, use a lower threshold. They define a stripper well as producing less than ten barrels of oil per day, or 60,000 cubic feet of natural gas.

But in general, everybody agrees that they’re called strippers because operators theoretically strip the last remaining value out of the ground before they’re retired. Sometimes you’ll see that stripper wells are referred to as marginal wells, since they require a higher price per thousand cubic feet or per barrel of oil to be worth producing at all.

And just to give your readers some context, a typical stripper well in Appalachia, a gas well, produces about 7,000 cubic feet of natural gas per day. And compare that to a new horizontal fracking well that produces about 30 million cubic feet of gas per day – to give you an idea that we’re talking about very low producing wells. And most of these stripper wells that we’ll talk a little bit about today are producing even smaller amounts than that.

MR. DANIEL SHERWOOD: What a stark contrast between the two.

MR. TED BOETTNER: Yeah, it’s such a stark—I mean, just think of that average daily production of 7 Mcf or 7,000 cubic feet for a stripper well in Appalachia. Where a fracking well, you’re talking 30,000 Mcf or 30 million cubic feet of gas per day. So, there is a big difference, right? That’s part of the reason we looked at this report was—we’ll talk a little bit about the shale revolution too.

But just to put that in context for people, most of these wells are old and, like I said, are producing very little gas or oil. And many are at serious risk of becoming orphaned or abandoned. And this could potentially cost states billions of dollars in cleanup costs over the next decade. And while high volume fracking wells produce most of the oil and gas in the United States and in the Ohio River Valley, stripper wells make up about 90 percent of active oil and gas wells in the Ohio River Valley region. And they makeup over 75 percent nationally. So, while they’re producing very little of the total pie of production, they remain the largest portion of the asset retirement obligations that exist by far. So that difference is another one of the reasons that we looked at this.

And another reason too is the number of stripper wells. We know this has grown dramatically in the last two decades in the Ohio River Valley region and especially the number of these ultra-low producing wells. These are wells that arguably should be decommissioned. These are wells producing less than one barrel of oil equivalent per day. And they used to make up in the Ohio River Valley about half of the wells. Now, these very ultra-low producing wells comprise three out of four of all the stripper wells.

MR. DANIEL SHERWOOD: And I just want to give a little big picture painting here for our readers. You and I have our heads down in this every day. But I don’t think people really understand your report here is unique and rare. In the last couple of years, we’ve gotten a lot more attention on the issue of AROs, but that has been solely, in my opinion, almost solely on idle or inactive non-producing wells. And what Ted has done here in this report is he’s finding this huge—you are finding this huge, huge class of assets that are otherwise not talked about. And in some instances, like you point out with the IOGCC, are kind of bandied about as an economic boon once prices recover. But instead, this kind of flips the script and it says, hey, look, this is a huge asset base in our country and in the region, and there’s genuine risk here. And you brought to the forefront otherwise unknown information like looking at how little these guys are just sputtering along with just a teensy bit of production and how these operators can’t afford to bring them down, decommission them, those AROs that you talk about.

So, it makes sense to me that you gave it a look. I’m happy that you gave it some attention and I appreciate it. I think that was a very clear definition, yes. For our readers that followed our Diversified investigation, a lot of the experts that we interviewed during that did discuss it as marginal wells. And this is just me reading between the lines – I don’t know if this is the case—I think industry seems to prefer to use the marginal well language because it seems less ‘extractive’ than stripper wells. But they’re practically the same thing.

I also noticed, Ted, in your definition—I didn’t realize this in reading the report—the lower threshold from the IOGCC. Because again, it makes sense that the industry wants to keep these online as long as they can, that life support. So that’s helpful. Thank you. And kudos, by the way, for such an amazing and thorough report to be out there. I hope that it’s as valuable as a reference material for everyone else as it has been for me already.

Now that we know what they are, we can dive in a little bit. And you gave a prelude to some of these findings here, but I don’t think it’ll hurt to repeat. Now, you found that the Ohio River Valley region had a higher proportion of stripper wells than any other in the United States, based on the proportion of active wells therein. And you also found that those wells not only are a higher proportion, but they’re also less productive in the ORV than other regions. Zooming in further, you identified—this is what you just mentioned—that the number is increasing and that they’re becoming even less productive.

So, to boil all four of those points into one sentence, the Ohio River Valley has more and less productive stripper wells than any other region in the United States, and the problem is only getting worse. So, I’m going to set you up for where you’re taking us. Can you put all these data points together for us? How does this help us understand the changing importance of stripper wells to the U.S. economy compared to, say, the 70s or the 2000s? And why are your findings so important to policymakers and those sitting in offices in Pittsburgh and Charleston?

MR. TED BOETTNER: Yeah, I can try to. So overall, I mean, this is the context. The stripper wells are producing half of what they produced two decades ago. And that makes perfect sense, right? With the big high volume fracking boom. However, in other words, though, the stripper wells, they represent a smaller share of oil and gas production, but they actually comprise a greater share of active wells. So production is declining in the Ohio River Valley. In the four states that we looked at, West Virginia, Ohio, Pennsylvania and Kentucky, we found that production has gone down by 50 percent. So that’s a lot, right? And we’ve seen that before the big shale fracking boom, these wells provided 80 percent of the production in the region. Now, just 2.5 percent of production, which doesn’t make logical sense to anybody.

But when you flip the script and say, well, wait a minute. Yes, that makes perfect sense. But also because the number of stripper wells has grown—just over the last two decades from 2000, we’ve seen a 42 percent increase. Basically, 125,000 more wells are defined as stripper wells in this region since 2000. There’s just more. They make up a much larger set of these active wells. And what that is telling us is that they’re going out the door and that eventually these are the wells that will have to be plugged and decommissioned. And as they decline, it makes more sense for policymakers, investors and others to look at that and try to figure out what’s going to happen in the future there.

MR. DANIEL SHERWOOD: I was just going to say this is textbook late-stage oil and gas production. You’ve identified each factor that comes to bear at the end of a lifecycle for an oil and gas asset. So, you were going to say at the end of the fracking boom?

MR. TED BOETTNER: No, I’m just saying that before the fracking boom, like in the early aughts or early 2000s, stripper wells occupied a more important part of our nation’s oil and gas production. And our national interests or energy security, they were talked about more in that term of having a domestic source of production to meet the needs of our nation. And that’s just changed dramatically.

An interesting part of this report is, well, how is policy changed during that time? What was policy like before that? During that time, ever since the 1920s and 30s, policymakers went to great lengths to keep wells alive as long as possible. And they’ve done this with tax subsidies, price controls, tariffs and other policies. But since that time, there has been this boom in high volume production from hydraulic fracking, and this has dramatically increased domestic oil and gas production, as everybody knows. And today, some of those policies are still in place in a combination of these federal and state taxes, but also just relaxed enforcement at the state level that has created an environment where that has been used to avoid these plugging costs for operators. They’re just barely staying alive. And as prices fluctuate, they become uneconomical. And what we’re finding is many of these wells are being idled and not being put back into production. Or in some instances, people are getting a little production out of them every year just to keep them from being decommissioned.

MR. DANIEL SHERWOOD: That’s right. And I think a perfect capture of what’s going on here is the underlying economy and the underlying production trends have changed. And the regulatory mechanisms that determine how things work, they’re uneven. And because of that, there’s going to be an issue. It would appear, based on your findings, that these issues are going to increase. So lastly, on that first section of your report – and, I mean, I could spend two hours talking about this report with you. So, I don’t mean to move us along too fast, but there’s just so much good stuff in there. But on that first section, I did just want to have you tell everybody kind of what did you find too about the ownership of these wells? There’s kind of a common notion, that based on your findings, I think you’ve refuted.

MR. TED BOETTNER: Yeah, I mean, I think another reason we decided to look at stripper wells was the concentration of ownership. While typically, stripper well operators are portrayed as sort of mom-and-pop companies, what we found is that this isn’t true. If it ever was true before, it’s not true today. So just today in the four states that we looked at, we found that most stripper wells are owned just by a handful of operators. So, in the Ohio River Valley states, 17 companies own half of the stripper wells. And by far the largest owner, as we talked about earlier, is Diversified Energy. And they own over 50,000 stripper wells. And interesting enough too is Diversified Energy is also responsible for about 43 percent of all stripper well production in the region.

And this high concentration of low producing wells in one company’s portfolio presents a risk to states, that they could become orphans or wards of the state. Because if Diversified Energy or other companies that own these stripper wells that are operating at that margin and given the possibility that one of those companies were to go out of business, states could be on the hook for billions of dollars in cleanup costs. That’s because the operators are not required to set aside sufficient cleanup costs upfront. Most of these operators have bonding in all these states. But as we know, and we’ll talk about later, is that bonding coverage is just a tiny fraction of what it costs to decommission these wells.

MR. DANIEL SHERWOOD: Yeah. And yet again, I mean, are we surprised to see Diversified at the center of another strange data point? Where, yes, their business model is so novel, I think that there’s just a number of things that would suggest that the company deserves greater scrutiny.

So, let’s talk about bonding. I think that’s a perfect transition. We’ve done a lot of work on AROs here, so I don’t think we need to go through the definitional stage necessarily. But I do think it helps just to give a quick primer on bonding and how it works in oil and gas. I love, Ted, your policy take on bonding and hope that we can get to that near the end. But before we talk kind of more esoterically about it, what is it? How does it work? And what did you find?

MR. TED BOETTNER: Yeah, just really quickly, usually before a company can drill an oil gas well, it must set aside funds to plug and restore a well site after the production is over. These funds, they’re sometimes cash, but more likely to be bonds, like performance bonds or surety bonds. And

these are sort of like debt-like obligations that’s supposed to provide a financial incentive to drillers to properly decommission their wells. And each state has different bonding requirements. Most states have either single bonds or blanket bonds. And just to give you an example, let me take a state here.

For example, Kentucky. They require individual bonds for some of their wells, and then they also have blanket bonds as well. So, in Kentucky you can get a blanket bond for hundreds of wells just for $20,000. And Pennsylvania operates in a similar fashion as well, where like a single bond might be $25,000 for a well. But a blanket bond in Pennsylvania is $25,000. So, you can own in Pennsylvania a thousand wells, and you’ll just have to bond to that $25,000. As your readers might know, typically it costs more than $25,000 to decommission or plug an abandoned just one well.

MR. DANIEL SHERWOOD: A single well?

MR. TED BOETTNER: Yeah, so the bonding is way out of line with the actual cost of decommissioning these wells. And this major problem in bonding has been exacerbated by blanket bonds especially. And as we talked about earlier, remember that concentration of ownership, it makes sense for most of the stripper oil companies to use blanket bonds. And you end up with a very small bonding coverage.

So just to give you an idea, as we talked about in the report, these are very conservative low numbers. At the low end, it cost about $30,000 to plug an abandoned well in Appalachia. But the average stripper well in the state only has about $214 of bonding coverage. And when I say that, that doesn’t mean they have $214.00 in an account. They’re paying an annual premium on that. So, it’s even less than that.

One thing that we looked at in the report was how much total bonding do all of these stripper wells have in the four-state region? It’s less than $40 million. Those are our estimates. And the cost to plug all of these wells. So there’s 177,000 stripper wells in the region. So if you were going to plug those at like $30,000 a well, you’re talking around $5 billion. But the bonding coverage is only about $40 million. So, there’s a huge gap between those two. And it’s a significant problem across the country. You’ve seen states like Colorado trying to address this problem head on because they’re worried. Everybody is worried that especially these stripper wells are going to become wards of the state, and taxpayers in these states are going to have to pay for that—or somebody else is—because the companies just don’t have enough money. Like I said, imagine if you bonded something at $40 million that cost $5 billion to deal with, it’s in some instances cheaper for some of these companies to just declare bankruptcy than to actually pay for the decommissioning cost or go out of business than plug wells.

MR. DANIEL SHERWOOD: In most instances, right? I mean, think about the numbers that you just said. The only times where it wouldn’t be cheaper for an operator to do that would be if they

operate two or three wells. Otherwise, every single time, just given the regulatory framework, it literally is baked into the equation that, yeah, you file bankruptcy and return the obligation, or foist the obligation really, onto the public.

So, you brought up premiums, and I’m glad you did, Ted. That’s my favorite. We’ve talked a lot about bonding here, and I’ve never once heard this kind of analysis used in this way. And so much so, you might remember when we were working on the report together, you and I, I didn’t even understand where you were going with this. But can you explain to our readers what you did with your premium analysis? It’s straightforward math. And I think it’s a good talking point for anybody who’s going to the Hill to try to communicate this stuff to policymakers.

MR. TED BOETTNER: Yeah, I mean, another way, what we tried to say is what would full cost bonding look like in these states compared to what we talked about earlier? Another way to estimate it, I mean, this acts like an implicit subsidy for these companies because they don’t have full cost bonding. So, another way to estimate this subsidy is to consider what the annual premium that would be paid for full cost funding. As we talked about earlier and say the full cost – and this is on the low end—is about $5.3 billion. If companies paid an annual premium, let’s just say—in the report we used 2.5 percent, which is very generous, most likely it would be a lot higher. If all stripper operators paid a 2.5 percent annual premium, and the total bonding now is $5.3 billion, premiums would amount to about $134 million annually, or about $750 per well, assuming all the stripper wells could get bonding coverage.

One thing we try to talk about in the report is that – and we talked about this too, Daniel—I think that’s highly unlikely. I don’t think a lot of the stripper well companies would be able to get a bond of that amount. And because of that, I mean, this acts like sort of an implicit subsidy for these companies. If stripper well operators in the region had to pay a premium of, let’s say, $750 per well, it’s likely many of the wells would become uneconomical since many of the wells are barely profitable as it is. We’ll talk about that a little later. But either way you calculate it, it’s clear that insufficient bonding requirements constitute an implicit subsidy for stripper wells that could likely cost taxpayers in the future. Because at the end of the day, all these wells need to be plugged and abandoned or decommissioned. The question is who’s going to pay for that? And the ability of companies to prolong that decision as long as possible and potentially to go out of business presents a huge risk to states and to its fiscal stability to taxpayers in all of the states as well.

MR. DANIEL SHERWOOD: And correct me if I’m wrong, in other words, that what you’re saying is if policymakers were to implement full cost bonding, due to kind of what you already laid out in the call so far of the reality of on the ground, what’s going on and what these operators are dealing with, if regulators were to implement that, it’s kind of like it would send them out of business? Like it’s two different worlds. There are other policy mechanisms, like a production tax, as you suggested in the report, that might be more beneficial and be more rooted in actually addressing the problem – is that correct?

MR. TED BOETTNER: Yeah, I think you want to be careful in terms of policy prescriptions. I mean, full cost bonding, a lot of states are looking at that, other places. That would have been great to do at the very beginning of this crisis before it happened when these wells were first being permitted. And it makes a lot of sense to go forward doing full cost bonding or even going to half cost bonding would be a dramatic improvement, especially for newer wells, newer permits.

But we’re talking about very low producing wells. Some of these wells, they’re not even producing a couple of thousand dollars a year. I mean, you get into a problem where you don’t want to incentivize an avalanche of new orphan wells. And that’s one of the things that we came away with. The report is like I think you want to really figure out how are you going to deal with this problem fiscally as a state, or as a policymaker? And I think one of the easiest ways to deal with that is sort of analogous to how we dealt with abandoned mine land funds, for the thousands of abandoned coal mines around the country. And that was to put a small fee on production the same way they do with the abandoned mine land fund. And to put that into a fund or an escrow account and to use these funds of current production today to deal with the past and the future going out.

Because I think from my perspective, and this analysis too, bonding is not going to solve that problem of stripper wells and inactive wells at all. And only using the current production where the money is today is one of the few ways to deal with that.

MR. DANIEL SHERWOOD: There you go. I mean, that makes sense to me. You’re in good company, Ted. I think it’s Shakespeare who said the past is prologue to the present. So yeah, very interesting and I think a good take. And I’ll just say from where I sit—take this for what you will—but I would argue that Ted has a unique view in this space and that most of the people I speak to are pretty sold on, or take for granted that, the solution here is raising bonding or changing the bonding regime. I think there’s something to consider for anyone working on this.

All right. Well, we’re already at 11:30. I just wanted to hit on taxes. Maybe I can get to it depending on what kind of questions—I haven’t looked at if I’ve gotten any yet. But before we open to questions we need to touch on the uneconomical wells there. That’s very pertinent to issues that we cover at The Capitol Forum. And, of course, Diversified is yet again a central character.

Ted, this parallels the work you did in identifying the scale of stripper wells. But it is slightly different. And I think most importantly, you lay out how it makes more sense to keep these wells online, even if they’re losing money versus retiring them. You just mentioned something similar based on, again, how low they’re producing. But can you just show us how you got there with a little bit of the math? And that Pitt—I’m pretty sure it’s Pitt—study and kind of just talk about what you mean. I got an email from a subscriber last week that was like, “Uneconomical? If it’s producing, it’s economical.” And I’m like, “well you’d think that. But it’s actually not the case.”

MR. TED BOETTNER: Yeah, absolutely. Like you said, in many instances, it may be cheaper to put off decommissioning wells that were losing money or has had a negative cash flow for years. Because lease operating expenses is what we looked at to determine whether a well is uneconomical or not. And we drew this from a study from the University of Pittsburgh that’s highlighted in the report. And they came up with a threshold which I think is ultra conservative of what a well needs to produce to be economical. And they base this on sort of just a small portion of costs to operate as well. So, they looked at lease operating cost. Because a lot of these conventional wells when you go out there, they don’t require a lot of attention, but they do require some.

So just to give you an idea, we just assumed that these wells cost about $886 per well to maintain. That’s pretty low. People I’ve talked to in the industry say that’s just ridiculously low. And we say, well, if they cost about close to a thousand dollars to maintain every year, how much would they have to produce at current prices and projected prices in the future to be economical? And we used a figure of 500 cubic feet of gas per day from the study that’s mentioned in the report. And these are deemed to be highly likely to be uneconomical even if gas prices rise considerably and that should arguably be decommissioned.

And what we found is that about one in seven, about 31,000, of the active wells in the four-state region are uneconomical arguably need to be decommissioned. And like I said, this threshold is quite low. Other states like Colorado have determined that anything that’s producing less than one barrel of oil equivalent today is uneconomical. If we did that, we’d be more at over 100,000 wells that are uneconomical. So, we’re trying to be ultra conservative here in looking at that.

And like I said, the company that owns most of those uneconomical wells is Diversified Energy as well. And that was one thing we touched on in the report is just to sort of gauge, look at that, look at the wells that are uneconomical. Because there’s this thought process through policy and through other organizations that have maintained that these wells, once you plug them, they’re gone forever. But they can always produce. Like your commenter said, well, they can produce. But at what price? And when is the time to shut them down? Because you can have a couple of years of negative cash flow. It takes a while for that negative cash flow to be at a point where you arguably want to decommission the well.

So that’s what’s happening here, too, is that they just become – when we looked at Diversified Energy, we found that about 3,800 of their wells weren’t economical. Like I said, that’s just using a very, very conservative number and we didn’t even get into—if you want to talk too about all of the inactive wells. One of the findings of the report that I thought was remarkable – and I could have written a whole report just on this—was the inactive wells as well. So, when you add them all up, we found that there were about 223,000 wells that are active and inactive in the four-state region that arguably should be decommissioned today.

MR. DANIEL SHERWOOD: I’m looking at that chart right now. That’s a great chart. And for those of you who have not read Ted’s report, I realize that I haven’t plugged it explicitly yet. I highly recommend it. Obviously, this call is basically an implicit plug. But don’t use this call as a substitute. We’re only skimming the surface of what we’re talking about here. And he has, I think, 25 gorgeous figures that just all tell stories in and of themselves.

And for proportional context on the figure that Ted just said of 223,000 wells in the region could be uneconomical. In the entire region, according to our database—and that includes multiple states that aren’t even included in this analysis here, and this includes plugged wells—is only 918,000 wells. So in all of Appalachia, there’s a million wells total, including plugged, total. And of those, a fifth—a neat fifth—that are considered active or inactive and recently producing are uneconomical. It’s a huge, huge, huge red flag, I think, from pretty much anybody’s perspective.

And on the cost side of things, yes, I echo what Ted said. My sources agree that is an extremely conservative formula. I’ve had people tell me $3,000 a month. Obviously, there’s a lot of variance, right? Every well pad is different. Are they talking about fracked wells or conventional wells? And in my view, I don’t really care, because if you look at operating expense, if you look at cost, and then you look at production, that’s really all you need to know. And for an operator like Diversified, who has such a disproportionate number of these types of wells, if they can make it—I’m using air quotes here in my apartment—but if they can make it ‘economical’ by reducing those operating costs, well, it stands to reason that they’re probably cutting some corners that shouldn’t be cut. If EQT, one of the largest, and I would argue most proficient and best, natural gas producers in the country, if they can’t make it work, why can an Alabama headquartered, London listed, non-oil and gas veteran company make it work? It smells fishy at best.

So I’m all fired up, Ted. This is an amazing report. Here we are at 11:40. I have gotten a couple of questions, despite the kind of light attendance today. The best way for me to summarize these questions, and this is something I get often from the investor community when I talk about this issue, but they want to know when does the rubber hit the road? When are they going to start seeing this on their balance sheet? They, meaning the company. When are the companies going to start seeing this materially impact their businesses?

And Ted, I just want to say, there’s two different pressures here, right? There’s the pressure from the regulatory perspective, which is obviously slow moving. But then there’s the pressure from the production perspective and just like the sheer existence of, well, there’s a finite number of resources in the ground. And as time marches forward, as it’s wont to do, there will be less to pull. So, I know that your crystal ball is just as good as anybody else’s. I don’t expect you to say something like Warren Buffett-y over here. But I am curious as to what you think. And feel free to just pretend you’re at the dinner table talking to your kids. How do you see this issue manifesting itself in the future? Do you see regulators really going after operators? Or do you see operators picking up the tab due to ES

same? And people like you and I can continue to try to warn, try to highlight the importance of the issues. So what do you think? How do you see this playing out?

MR. TED BOETTNER: Yeah, I mean, I think there’s a lot of moving parts there, too, like you said. I’d like to see them take this into account. And I think looking into the future, you’re going to see further decline in stripper oil production as overall gas and oil, gas production especially, in Appalachia, will probably continue to increase. So the conventional well production will decline as well. And that brings into question Diversified and and our understanding of that company too and what they’re headed toward.

But another thing too is that the federal government, involved in the infrastructure bill, has about $4.3 billion for states to plug orphan wells. And included in all of that is money to create a better inventory system of their states and to do risk analysis of all these wells. So, I think you’re going to see a heightened understanding of what wells need to be decommissioned and which do not. And eventually, that can make its way into these companies’ balance sheets in a very large way. Because policymakers are going to be hit with something, a decision to make about what to do about this. And you are seeing states like Ohio who have put more money into the orphan well programs that are getting more serious about addressing this issue. And while there’s federal money to deal with just a fraction of the orphan wells that we know in this country, we’re going to have a lot better understanding of this problem over the next couple of years. So I would say in the future, it’s going to become more of a concern because we’re going to see even more stripper wells. And these new stripper wells could be these older fracking wells that enter the picture that cost $80,000 to $150,000 to plug.

MR. DANIEL SHERWOOD: Yeah, that’s a great point.

MR. TED BOETTNER: Yes, I mean, I could be very negative and say states are just going to keep doing what they’re doing and they’re not going to care about dealing with this issue. But we have seen a huge understanding over the last less than a decade of studies on methane emissions, of brine, of other volatile organic chemicals that are coming out of the wells that are contaminating water. And as places further develop too, this will become a larger issue. Who’s going to pay for this well? How did this happen? I think it’s only going to increase with time.

So, I would say that for stripper well operators, the future is not bright. I would take that into deep consideration that it’s hard to make money in the gas industry without drilling. It’s amazing that one company’s been able to do that without drilling per se, just acquiring these older wells. But it looks like in the future that conventional wells are going to produce even less and accumulate even more. And that means a larger liability. And as states understand this issue more, especially with this new federal funding, I think I wouldn’t be surprised if policymakers began developing more comprehensive plans to deal with this issue.

MR. DANIEL SHERWOOD: That’s right. Well stated. And may I emphasize that – did I hear any Chicken Little-esque scare tactics? No, that’s a, I think, pragmatic take. And I agree. And for a Capitol Forum plug, like it’s true what Ted said. After APA Corp., after we reported that there were hundreds of millions of dollars of unaccounted for asset retirement obligations based on their relation to the Fieldwood bankruptcy, when we went to them for comment, the company said to us, “Well, there’s no issue. Your math is wrong. You’re a dork.” And then fast forward six weeks when they have to file with the Securities Exchange Commission and the second sentence of their earnings report release was “we added $400 million to our AROs.” And that’s obviously going to impact, I mean, that explicitly impacts the value of the company.


MR. DANIEL SHERWOOD: And so, BSEE/BOEM did not move on APA right there. Like that was just their own diligence to shareholders. And I think exactly what Ted said. And having talked with EQT and other people in the space, they know, they see that people are circling. And so, whether or not it amounts to higher AROs disclosed to shareholders first or it amounts to a new regulation on the books, like what Pennsylvania is doing right now in trying to regulate marginal wells and plugging. I see that they’re doing that under Governor Wolf.

MR. TED BOETTNER: So, one thing just really quick too is when we’re dealing with Appalachia in particular, we’re talking about private land mostly, like over 95 percent, right? And this is a private property rights issue, and farmers understand this too. And when it becomes known that there is no real plan or money set aside to efficiently deal with this issue, this is when the litigation will happen. And I think a lot of these companies are at severe risk of mass litigation. And the evidence is accumulating quite strong that we have not set up a mechanism to efficiently deal with this issue. If you follow what I’m saying, though, as we learn more, don’t be surprised if there’s litigation. This is private land here. This isn’t out west. We’re not talking about mostly public and federal land. So, it can become a different issue.

MR. DANIEL SHERWOOD: That’s right. And we all know local courts in West Virginia and Kentucky, like the common law has established very clearly property rights in that regard. And that’s a good point to bring up. I mean, I’ve read a little bit of that contamination of farmland. So, this is a fascinating issue. And you’re right, there are a lot of moving parts. So, I think it bears repeating that we just need to continue to focus on this.

All right. We’re almost done. I’ve got one more question from someone watching Diversified. And you did mention this just most recently in your answer. Again, please read Ted’s report. It’s extremely comprehensive. He has an entire section about climate and does mention the Diversified Bloomberg report, which is what I got the question about. But people are wondering how bad is this methane issue? Is this really a pockmark for Diversified? Sorry, I’m just trying to synthesize this question. Basically, is this something – are we going to see more of this? I mean, I think, as

you just said, yes. But what does that look like? And is this going to hit—from your experience and observations, do you see the West Virginia DEP going out to Greylock and saying, hey, if you don’t shut this down because of these methane emissions? How does that look? I’m glad that you mentioned federal policy. Is it involved in that? I’m sorry, I’m having a hard time distilling this question. It’s basically like, is this methane stuff with Diversified, is it like ESG/Hocus Pocus from the left? Or is it an actual issue?

MR. TED BOETTNER: Yeah, I mean, I think, like I said it earlier, I think over the last decade, especially over just the last six or seven years, we’ve really gotten to focus on how much methane is being leaked from conventional wells and also fracking wells as well. It’s become more and more of an issue. And as people go out and investigate and just do small samplings of wells, like I said in the report, what they’re finding is that some of these circle wells are leaking large amounts of methane. Particularly, they’re leaking more methane than they are actually producing the gas they’re selling. And that’s remarkable. I mean, yeah, that’s a major issue.

And as lowering greenhouse emissions and carbon reduction becomes more of an emphasis in this country and around the world, and in states in particular, methane reduction is seen as a critical component, and it’s been debated, obviously, in the Federal Build Back Better legislation. It’s a point of contention right now. So there is a lot more focus on it. I would say that the findings in the Bloomberg report regarding methane, that is just the tip of the iceberg. In Pennsylvania, it’s a particular problem too. And I think you notice a very large problem when you transfer the wells too, from one company to another and then what’s taking place. There’s a massive divergence between what the reported methane is and then what it is when somebody actually goes out there and monitors that and tries to look at it. And I think it’s going to grow in importance for people.

And I think there are some companies that want to reduce their methane emissions. And there are people on Wall Street that will want to trade on it too. You’re going to see that all with this orphan well stuff is people willing to say, well, if you plug this orphan well that produces methane and then you’re going to see a lot of carbon offset stuff happening too. So, it is very important. I feel like we’ve barely scratched the surface. Because most states are not mandating. Most states do not have a database of really good information on methane leakage.

MR. DANIEL SHERWOOD: No. Well, we lack the technology. As you know, you have to have very specialized technological equipment. And even the margin of error is very—I’ve attended industry conferences, like hyper, hyper technical conferences, where the people are talking about the different underlying sensor and semiconductors and blah blah blah. And if the wind is like this and the sun is like that, then you can’t read it, and all this stuff. It’s a very nascent field.

And I think you’re right that this is a legitimate issue and that report was the tip of the iceberg. And if you think about this from a geological perspective, it makes sense. If people are putting holes in the ground to get gas, the gas is already naturally in there. That’s why it’s called natural gas.

Sometimes when you build a house, it’ll seep into your basement, right? So it makes sense if you’ve got a hole in the ground that’s not doing anything, it might leak out the methane. And if we haven’t even been able to read it from the flare point, how could we read it from kind of a nondescript location? So a ton to follow. Very robust conversation, as I knew it would be. Ted, do you have any closing remarks or any kind of final points you want to leave us with? And then we can wrap?

MR. TED BOETTNER: I just really appreciate the opportunity to talk to you again and everybody else about the report. I know it’s a bit esoteric. If you look around, there are no other reports on stripper wells. So, it’s like, wow. I’m breaking new ground here to do an analysis about it. But I just want to overall say it’s quite amazing. While stripper wells made up a larger portion of production two decades ago. They make up just a tiny portion. But their portion of active wells out there are mostly all stripper wells. And with that is a huge risk of billions of dollars in cleanup costs that could flow to states. And we should all be very concerned about that. And these companies, if they had to absorb those costs for these wells, the balance sheets would look quite differently. And if they had to pay for those upfront, like other companies do—if you’re a commercial real estate company and you have several buildings around neighborhoods, you have to get coverage for all of those buildings, not just one blanket coverage. So they’re operating much more differently than other businesses. And because of that and because of the lack of regulation, it puts them at real risk. And one company owns such a large portfolio of those wells, we should be very concerned. And there can be sort of a too big to fail mechanism. But you don’t want to be around if it fails.

MR. DANIEL SHERWOOD: That’s right. Yeah. Wow. Look at that. It’s like you had that prepared for us. Great. Well, Ted, thank you. I really am appreciative of your time. And for those of us joining, sorry this ran so much longer than it normally does. And we appreciate you greatly and look forward to more. And just a little preview, there might be an ORVI report coming out on Diversified in particular. So stay tuned, ladies and gentlemen. We’ve got an exciting year in store for sure.

MR. TED BOETTNER: Thank you so much, Daniel. Thank you to The Capitol Forum for all of your help and the ability of getting some of this information out there.

MR. DANIEL SHERWOOD: Absolutely. It’s our pleasure. Thank you, Ted. And thank you, Ashley, for setting us up here. I’m going to wrap. I hope everyone has a very happy New Year, and thanks again.