May 09, 2023
On May 5, The Capitol Forum’s Teddy Downey, Daniel Sherwood, Sharon Kelly and Julia Arbutus held a conference call to discuss the most pertinent issues impacting energy markets and policy. The full transcript, which has been modified slightly for accuracy, can be found below.
TEDDY DOWNEY: Thank you, everyone, for joining today’s Energy Conference Call. I’m Teddy Downey, Executive Editor here at The Capitol Forum. We have a full house. We’ve got our entire energy team on the call today. I’m joined by Daniel Sherwood, Sharon Kelly, and Julia Arbutus. Thank you so much for doing this today team. And we’re going to be talking about just our typical, very interesting, energy issues. Let’s get started talking about EQT today, Daniel, and this Tug Hill acquisition. And I’m just going to read a bit of it.
Actually, my old colleague, David Khani, and I used to work together at FBR. He gave me my first job as a Wall Street/policy analyst. So this is interesting for me. So EQT updated investors April 27th on the first quarter performance and gave full year guidance. At the high end, the company is planning to remain at or under its two Bcfe/d annual production ceiling. In response to questions around further production curtailment amidst lower natural gas commodity prices, CFO, and former Teddy Downey colleague, David Khani, cited output below maintenance level as already contributing to EQT’s share of the reduction in gas to help balance the market. We’ve had this maintenance level comment come up before. When you hear that, what does that mean to you, Daniel?
DANIEL SHERWOOD: Yeah, we pay close attention to how industry participants communicate with themselves. And we wonder sometimes about whether there’s some coordination or not. You know, we have a Coordination Out Loud series, for instance, that flags comments that talk about collective reductions in price or supply, for instance. What stuck out to us on this one is talking about their share of the market. And so, yes, the full quote is referencing maintenance capital, waterline issues and this production curtailment. So let’s just decode the statement in and of itself, and then we’re going to use that as a framework to talk about EQT’s philosophy as it relates to production and then how that factors into midstream components of the Tug Hill acquisition as they just asked to amend the outside date for its special mandatory redemption provision.
So maintenance mode, just generally, let me pull up my notes here. Maintenance CapEx can be considered the cost of sustaining current revenue and profits for a business. That’s kind of like your Investopedia definition there. As it relates specifically to oil and gas, you can think of it as just the capital that a producer would spend to keep production flat. So, there’s a lot of different things that go into producing oil and gas, of course. And you don’t just put your capital forward, you drill and then it just comes out willy nilly. There’s obviously costs that need to go into the well pad to sustain and continue that production.
Okay. So that’s what he’s referring to when he says maintenance capital. So let’s look at the whole quote, the full quote here. So he says—this is in response to that question about so, you know, “prices are low. We don’t need to see a lot of output out of you all. Is there anything you’re going to do?”
“Yes, and I’ll just add”—this is the quote “due to the waterline issue last year, our production has not—is below maintenance level normally by, we’ll call it, two to three percent already. So we’ve actually contributed I would say our share a little bit of the reduction in gas to help balance the market as well.”
And so I think the last definitional point of that statement to deconstruct is the waterline issue. What’s he referring to? So hydraulic fracturing is, you know, the technology is a very water intensive process. It requires water both on the front side and kind of on the back side. What I mean by that is when you’re pressurizing the well to make the gas come out, you’re also injecting water and proppant. And that’s a part of what’s increasing the pressure and can unlock a lot of well the efficiencies.
So you need to get the water to the well pad. Do you truck it in? Do you pipe it in? Do you have a water recycling facility that can reuse some of that pumped water as it comes back out and reinject it? And so that gets to the second part. So out of the well comes the water and then you need to either treat it, haul it offsite or possibly reuse it. So that’s how water midstream infrastructure works in the fracking space. So what’s he talking about? Waterline issues. Okay, so let’s dive into that. And before I do, Teddy, any questions before I talk about the midstream component and how that factors into Tug Hill?
TEDDY DOWNEY: I am about to have a lot of questions, but I’m good right now. I know I’m going to have a lot. So keep going.
DANIEL SHERWOOD: Okay. Awesome. So in the last couple quarters, I think it was Q3 – it was in the October 27th earnings call – EQT management discussed constraints leading to 30 percent less wells turned in line, which means you drill a well and then you turn it into production. There’s a kind of a weird phase once you drill initially to test how good is a well. How much is coming out? Is it better with more pressure, less pressure? You know, I’m simplifying things. And then turning it in line is finishing that process. This bad boy is up, online and producing.
So it gives you a 30 percent less of those wells turned in than forecast last year. And they cited third party constraints along with, “water restrictions due to drought conditions in parts of the basin.” So that’s an interesting climate change pressure. But they’re also kind of conflating the natural issues of drought with construction issues that they also had in building out this midstream infrastructure. So that was a little bit of some wordsmithing.
These issues led to a seven percent decrease in production in 2020, which they then could delay and have it come on in 2023. So what this comment is about is being able to balance the market – they had issues and delays last year and now they can kind of drag their feet, which is standard, of course, drag their feet in bringing on other wells to even further decrease that total production output since the underlying price of natural gas is historically low right now.
And so this is what gets to our interesting point about market share and about competition, is if you look just at the large macro numbers of natural gas, it’s a big, big market. And Tug Hill, for instance, is not that huge as a overall percent of natural gas production. But we have to look at how you define that market. The Appalachian Basin is an infrastructure constrained region. And control over midstream assets, in this instance, just the water assets had a seven percent impact on production. And you look at the quotes over and over and over again about what EQT says. I mean, there’s four hits just in that earnings call alone where they use the word “control” in regards to Western and Northern West Virginia production due to the operation of those XcL midstream assets which are included in the Tug Hill acquisition.
So, Sharon’s done a great job of informing people about this of how are we defining this market? And if you look at the Marcellus/Utica, and if you look at the basis differential between what it looks like to sell gas in basin versus out of basin, it’s big. And if you’re talking about the control of those midstream assets and talking about the impact of those water assets and EQT increasing its control with the acquisition of Tug Hill – it will better help EQT influence those differentials. So that’s my kind of bigger take. Sharon has some stuff to talk about market share. But Teddy, if you have any questions before Sharon dives in, let us know.
TEDDY DOWNEY: Yeah, a couple of things. One is when he’s using that language—keeping our production below maintenance level, balancing the market, he is – is it actually more of a concern, in some respects, of when he said that about what it means for the midstream assets in the region? Can you just explain that to me? Because they’re trying to get something out, but they have monopsony power? Or what kind of power do they have over that? Do they own it also? Are they vertically integrated? Like, how are they controlling it? I just need it a little bit more explicit for me of how this comment, which is about output, then translates to an indication about the midstream assets. I know it’s in there. I’m just having a hard time mentally.
DANIEL SHERWOOD: Totally. So it’s twofold. The first step is they’re saying they’re cutting production even further below what it would look like if they were just keeping it flat. And then the second aspect of that is a huge component of what’s allowing for (a) that flexibility, and (b) more ability to control those operations is the midstream component. And I think that kind of gets to where Sharon, I think, can help me out here about this differentiation. Sharon, do you want to take it?
SHARON KELLY: Yes, absolutely. So, this is something that we sort of discussed a little bit in our last investigation into EQT’s transaction with Tug Hill. And so basically, like Teddy mentioned, if you were just taking a look at natural gas prices in the U.S., like your Henry Hub price, your Waha gas price, that’s roughly $2 around now. But the thing to keep in mind is that Appalachian producers, the price that they are actually receiving for the gas that they sell isn’t directly—it’s not directly priced to that benchmark. There are essentially price adjustments that are related to transportation costs. And we heard, just before Khani’s comment, Toby Rice talking about EQT’s view on “local prices,” right?
If you’re looking at the price that matters to EQT, that price is the local price. And part of what goes into creating that local price—and this is something that EQT has historically been pretty explicit about—is in their view, like their philosophy, on what informs a local price is partly this midstream element, right? It’s partly natural gas pipelines. They’ve also talked very often about their view that the Appalachian Basin is pipeline constrained. And so there’s perhaps competitiveness differences there.
DANIEL SHERWOOD: And that they don’t want to unload the pipe that they do have. They do own their own pipeline assets, and they view those as crucial to “controlling” the operational footprint and gaining more of those assets, they again say explicitly, will increase their ability to control those same dynamics. And then you take one step outside of what they don’t own and one of the largest midstream players in the region is Equitrans, which is a spinoff of EQT. The last time I looked, EQT was its largest customer by a big margin. So it just brings very interesting questions and I think it helps us, kind of, again, narrow further how these markets could be defined. And so EQT has more visibility into another 800 MCF from Tug Hill production and where that’s going, what pipe, when, at what rate? Now, that’s just one more portion of either out of basin or in basin midstream control that they say they want.
TEDDY DOWNEY: It makes sense that there’s control here. I’m curious a little bit just about how the price works because we’ve got these local prices. So, EQT, they have to use the water to get the gas out. Then they get the gas out. Then they get it into the pipeline. They own the pipeline or some affiliate owns the pipeline. They basically own or have some influence or control over the pipeline and then when it gets out, someone’s paying for it at the other end. Are they charging—they’re charging for all those? So is it that they own all these different little pieces and they can kind of like pick wherever they raise, change the price? They have control over the price also? Or I’m just curious about that. Or am I making this too complicated?
DANIEL SHERWOOD: No, it’s confusing. The water component, that would usually probably go in operating expenses. That would be covered by the company. And they’re realizing synergies there by not contracting with a third-party water shipper or provider. As far as like who makes the money and when, it could depend. And one of the things that they also love about the XcL Midstream footprint is the gathering assets. Pipes can be sorted into gathering and transmission. And then you also have to think about processing costs and how those impact the price.
The most obvious control that EQT has over the pricing of the gas at the end of the day is the volume of production. And think of the water side of things as influencing that total number in production. That can have a big impact on total output or make it easier to take a lot of gas off the market. And then that’s what would have an impact on both pipeline demand, which would influence costs that you contract with third parties to ship your gas out of market or it would impact, could further depress it, if production goes up, local prices, right? Because they’re unleashing more production into the local market.
But in this instance, they’re doing the opposite. They’re taking that production off the market. And as they forecast to do as well with the Tug Hill assets. So that’s not necessarily what I would expect. You would expect you gain more volumes of production and more volumes to ship, and then you would use that capacity. But demonstrating that you want to pull back a little bit and then you want that control over the water assets, for instance, that’s kind of what we’re discussing here.
TEDDY DOWNEY: Got it. And so just to bring it back to David Khani, he’s signaling, hey, the market should be cutting production now actually. We should all be cutting production. We’re doing our part. But it has bigger resonance in this area because it’s not just the production that they control. They also control these other midstream assets. And it’s like when he says this, it kind of matters more or it has a bigger impact.
DANIEL SHERWOOD: That’s exactly right. And to end this, I’ll say in November 2020, when maintenance mode became kind of the de jure term of the oil and gas industry to talk about sustaining production levels and when capital discipline became a theme, this is Toby Rice. This is November 2020. This is a while ago. “Looking at the strip”—so that’s the price – “Looking at the price of natural gas, there is clearly a need for more discipline from EQT and all other operators to achieve this,” referring to future prices coming up so that they could eventually produce more. So this is a years’ long, you know, they’re saying it explicitly. And it’s just, in my opinion, there’s so many levers on the production side—that’s where this water stuff has really come to the top of this. This is something that can have a seven percent impact on your production output, that’s larger than I would have guessed for water infrastructure not coming online or having issues with a drought.
TEDDY DOWNEY: And we could spend the whole time on this. So I do want to double down on what does this mean in relation to the Tug Hill acquisition and how it fits in this philosophy and EQT’s role in the market as this kind of, you know, sort of organizer of cutting volumes?
DANIEL SHERWOOD: Sharon, do you want to bring it home?
SHARON KELLY: I think really it simply speaks to sort of how EQT has expressed, like you said, its philosophy, its view of how this market works. And so, if you’re looking at like a local market where EQT – which as we know is the nation’s largest producer of natural gas, but they are particularly focused in this one region – operates, I think anytime you hear them talking about things like balancing the market, like contributing their share to balancing the market, things like that, it reflects their concept of how this local market works. And I think that’s really why that caught our attention.
TEDDY DOWNEY: I want to ask it another way just so I have it. I mean, maybe I’m being a little too Machiavellian here or cynical or whatever you want to say. But let’s say you’re EQT. Can you just be like, listen, we’re going to shut down our water. We’re cutting it. We really need to cut volume. This water that you need in the area, we’re just going to turn it off for two weeks. No water for you. No water for you. Is that plausible? I mean, am I overthinking this? You know, if they’re controlling this water and they’re like, oh, I notice that this person over here is ramping up production. Maybe they don’t get water next week. Maybe they don’t get water this month.
DANIEL SHERWOOD: Maybe I’ll buy them. That’s what they’re doing with Tug Hill. Or maybe I’ll buy them. You know, this water system is their water system. And so, they built it to their assets. Do they have third party agreements with other people to use that water? Maybe. In other instances they would. And would that happen – cutting off access to other customers? I’m sure it could. So I think what you’ve described is a possibility. I’m not saying that EQT’s done that. What we are saying in our investigation is that we see what EQT is doing is this acquisitive nature of taking on those big producers and then literally reducing that output as they’ve modeled with Tug Hill and did with Alta.
TEDDY DOWNEY: And so, in effect, they acquire Tug Hill and they’re just going to have more power and this type of language is going to resonate a little bit, have a little bit more fear in the back of your mind, if you’re one of these other operators. All right. I should probably do what I’m being told to do here. I should probably get in line, what have you. I mean, it’s really interesting.
I mean, when I think about it, what’s interesting to me is like, okay. You know, this is not just affecting the price. I mean, this is like these communities rely on this work, right? Like these wells being online, this work being done, And if they’re just like we’re turning things off for a while. Like, what does that mean for all of these communities in Appalachia that have workers and rely on this type of economic activity?
And the idea, I mean, my old friend David Khani over here, can just cut off their economy locally, it seems problematic. It seems worth thinking about as well, especially because regionally, like you said in the overall market, there’s less, you know, it’s still a small percentage of production. But tell that to the worker in Appalachia who’s not doing anything for a few months when they’re like, we’re shutting off the water for your well or something.
All right. Like I said, we could spend another hour on this. But let’s move on. We’ve got another very interesting topic here, Diversified plugging trends, one of our longest standing investigations. Throughout Diversified Energy’s decade of acquisitive growth, its large inventory of low and non-producing wells have been subject to regulatory and legal scrutiny. What do newly added Upstream spud and depth data reflect about the company’s early plug jobs in relation to the rest of its inventory of unplugged, nonproducing wells. I love Upstream. I’m excited to hear the latest from what we’re seeing.
DANIEL SHERWOOD: Yes. So Julia spent four months working with our tech team tediously and fastidiously collecting new data points for the back end for Upstream users. And we wanted to bring it to our users’ attention to tune in that this is something that’s still being built out, but it is much more robust now and this is a good example of how you can use these data points for analysis.
Quickly, as Teddy said, this is a longstanding investigation. So I don’t want to bore anyone. But as a refresher, Diversified’s business model relies on this huge asset base and extending the lifeline of low producing wells and then being able to retire or, i.e., plug them in a cheap way. The way that they forecast those costs is generally below the industry average, and below regulators’ average. It’s just very low time and time again. An aspect of what we’ve done in our investigations is demonstrate how that number could be subject to possibly upward revisions as time progresses, in our opinion.
So here what we’ve done is looked at this these two different data points: the spud date and the depth. And Julia, if you want to share your findings with us and some of the top line stats as it relates to Diversified’s plugging program, we’d love to hear it.
JULIA ARBUTUS: Yeah, so as Daniel mentioned, we spent a lot of time building this out and adding it to Upstream for the analysis that we’re presenting today. We’re mostly looking at West Virginia, Pennsylvania, Ohio and Kentucky. New York, Tennessee and Virginia had three wells; it wasn’t super conducive to analysis, so when I say things like ‘across the board,’ I’m referring to those four states.
Across the board, average age of plugged wells in those four states is typically less than half of the non‑plugged, inactive, abandoned, orphaned and shut-in wells’ average age. Also, the average depth of plugged wells is roughly 600 feet less on average than those not-plugged counterparts. This is important because it seems to suggest that Diversified is plugging younger, less shallow wells, which typically is cheaper, so they can hit their—I think it’s a 200 well a year retirement obligation or goal.
TEDDY DOWNEY: They’re plugging younger and shallower wells?
JULIA ARBUTUS: Yes.
TEDDY DOWNEY: Or younger and deeper wells?
JULIA ARBUTUS: Younger and shallower. To dive into that, in West Virginia, there are about 250 plugged wells that Diversified owns with depths of about 2,700 feet. But they also have eight times more abandoned wells in that state with depths that are 800 feet deeper. So they have roughly 2,000 abandoned wells in West Virginia that they have not plugged yet, that are almost a thousand feet deeper, probably more expensive. Those plugged wells are also only about 35 years old, while those abandoned wells are, on average, about 55 years old.
But we’re building this out. We have pretty good data for West Virginia, Ohio and Kentucky. Pennsylvania is still something that we’re working on building out. We don’t have a ton of depth data for Pennsylvania yet, but we have a really significant amount of age data in Pennsylvania where plugged wells are about 12 years old. And conversely, inactive wells are about 32 years old, so, three times.
DANIEL SHERWOOD: And think what can happen to that wellbore, you know, in 30 years. That’s one of the things that can lead to higher costs for an older well retirement. There can be erosion, the metal in the casing can corrode, there can be environmental impacts like methane migration or release that need remediation. So that’s a pretty stark finding Julia.
JULIA ARBUTUS: Yeah, definitely can increase the price. And we did reach out to Diversified multiple times about this investigation. We sent them our whole spreadsheet. They have not responded to us. Unfortunately, there is nothing that I can say about their take on these findings, but it definitely seems to suggest that they’re plugging younger, less shallow wells because, likely, they’re cheaper jobs.
TEDDY DOWNEY: So it’s interesting in that maybe they’ve been saying, oh, we spend less than average on retiring wells. It just happens to be they weren’t being as transparent as Upstream is about the precise type of well, that they are retiring. And, I mean, this is probably not plausibly an accident. It’s not like they just randomly somehow picked all the youngest and shallowest to retire wells. It seems pretty improbable that that they would have done it unintentionally. That’s really interesting.
We’ve done so much work on these asset retirement costs. Has there been work on just like, obviously, we know intuitively or like based on your expertise, you know that it costs more. But has there been work on here on the sliding scale of costs for retiring these types of wells when it comes to age and depth and stuff like that? Like is that well known? So like theoretically, we can now go back into Upstream and say, hey, once we have all these numbers, we can sort of get a better sense of their actual retirement costs based on that?
DANIEL SHERWOOD: Yeah. I mean, that’s the perfect question. And that’s kind of why we wanted to do this. Ted Boettner at ORVI talks all the time about how it’s mind numbing to him that there’s not a national database or national survey even of retirement costs and the different variations. These things are highly localized. And there are datasets out there. There’s a big one from Canada. There’s one from New Mexico. There’s one in Pennsylvania from the PA DEP. But it’s never comprehensive. The Pennsylvania one is just on this type of well. The Alaska one is just from this company’s perspective, so on and so forth. So this area lacks a lot of transparency.
Our first investigation into Diversified in 2019, a part of our big first piece, was they kept—they omitted a really high-cost retirement job. So obviously, you’re going to look like it’s better when you remove the costliest job. And so we’ve watched this program progress year over year. And I’ve been kind of looking if that may happen again. And we haven’t seen obvious signs of that. We have seen them continue to decrease their costs. And Upstream is really the only place that I know of that has plug dates, that has these spud dates, that has nonproducing assets in an accessible fashion. And that’s one of the reasons why we built Upstream.
So I think one of the other interesting components of this is that Diversified has now become much more committed in certain aspects to its retirement obligations and buying this Next LVL and other retirement companies. So now they’re very unique as an upstream producer as they have an in-house, a relatively large in‑house plugging group. But again, in kind of the unique Diversified fashion, one of the ways that they’re going about this is they’re bidding out those services to other entities, including the government, to plug orphaned and abandoned wells. And as Julia investigated for our last published piece, some of those wells identified to the state are owned, appear to be owned, by Diversified and other active companies. And in some instances, not in this most recent investigation, but in others, Diversified has admitted that.
So there is some work, to answer your question about overall retirement costs, to be done. But there’s nothing as specific, nothing as granular or even as general as what we need. So this is kind of one of our efforts in trying to build that out. And Julia looked at those West Virginian bids, that Next LVL –Diversified’s subsidiary – is bidding on. And now Diversified’s bragging to their investors about efficiencies for getting revenues on plug jobs after they do their own. And it’s all very much a developing story.
TEDDY DOWNEY: Yeah. I mean, just because you have an in-house crew doesn’t mean it’s not going to cost a lot of money, right? So it’ll be interesting to see how this plays out. Because obviously, we know it’s a pretty big job. And to your point, how helpful the government is in terms of letting them offload their costs onto the public. Anything else? I mean, I obviously love Upstream and love all the myriad things we can do with it, and this is such a good example of that. Anything else I’m missing here, Julia, before we move onto the LNG expansion plans?
JULIA ARBUTUS: I don’t think so. I think we covered it all.
TEDDY DOWNEY: Okay, great. So last topic. FIP’s LNG expansion plans, lose shipper by rail. Pipeline and Hazardous Materials Safety Administration canceled New Fortress’ LNG by rail permit last week. What does that mean for FTAI Infrastructure’s expansion plans at its Repauno port facility in New Jersey? And I’m not going to say I’m surprised by this, just given how our reporting on the types of rail technology they were using. I think, was that last week or the week before, you know, recently? So I’m not going to say I’m super surprised by this. But I’m curious, just maybe you could talk a little bit more about did the agency give a rationale for canceling it, in addition to what you think it means for Repauno?
DANIEL SHERWOOD: Absolutely. And we weren’t surprised either, Teddy, but other people seem to be. And this is one of those places where The Capitol Forum really gives a lot of value add. Because you have management teams hyping stuff and obfuscating stuff. You wouldn’t believe the number of questions I got this week about Equitrans. In our view, it’s very much unchanged. We’ll explore that next week.
So here’s another example of that where our first story on the permit was in 2019. So that’s on the shipping side. And then on the export side, Sharon has explored thoroughly the issues with that Repauno project as well. So this is something we’ve been very on top of. It’s interesting that this is another example of kind of how companies are trying to move the industry forward, putting LNG on rail, exporting smaller volumes off the East Coast, things of that nature.
So let’s go in order of the question, Teddy. Thank you for framing it so neatly. Why did PHMSA cancel the special permit? They cited two things. One, regulatory uncertainty on their level. The Trump administration went forward on this rule and granted the special permit saying it was okay. Since then, this is updated. Our first story on this issue was saying, hey, the regulators going forward despite there being new information available to them and the agency said we’re not going to consider it.
Now, in the Biden administration, the agency revisited that decision and said we don’t feel comfortable with that decision. We think we should consider that new information. That’s the overarching rule. And then there’s a special permit going on underlying it. The New Fortress entity asked to extend it or renew it, and PHMSA said, Nope, sorry. They’re in part citing the issue I just discussed from the regulatory perspective. The second issue they cited was that New Fortress’ facility doesn’t look like it’s going to, you know, the company doesn’t even have one. You know, the company needs to get other permits. There’s litigation. There’s a pending FERC docket. We looked at your security filings. You say you still intend to build it, but you’re very, very early on. So why would we give you this permit?
Again, our early coverage demonstrated that from New Fortress’s perspective, if they weren’t able to ship the LNG by rail, it wouldn’t be economical because instead they’d have to use trucks. So without this permit, is this the last death knell of that project? We would say probably. But then so some people might say, yeah, we’ve kind of considered New Fortress walking away from the Wyalusing liquification facility. Maybe people thought that. Where that narrative wouldn’t add up is from the FIP side.
So that’s a Fortress-affiliated entity. It’s not a subsidiary of New Fortress. It’s got similar backing, financial backing. And it was spun off from another Fortress entity. And this FTAI Infrastructure, they operate this Repauno terminal that Sharon has visited in kayak, which I think is awesome. And we have reported on the fact that this facility, this export facility, had issues with the construction and management, has hyped up, hey, we can get all these NGLs out. You know, we have our whole NGL file. And we looked at it and it’s like, no. You’re not even running at full capacity. What’s going on here?
While all that’s happening, management is also saying and then we have phase two, and phase two is going to be bigger, better and badder and it’s going to focus on LNG. Focus might be a slight overstatement, but they definitely hyped the LNG component. They had their earnings call yesterday or two days ago and that language is gone. So I interpret that as the LNG component is scrapped. And now they’re pretending, not to be too harsh, but it does seem highly aspirational from my perspective, that they’re going to now do this phase two expansion of just NGLs. Just for a little bit of context there, their phase one, they just launched this new contract in April, and they’re forecasting $10 million EBITDA. But it turns out that 50 percent of that is three quarters of the capacity and they haven’t contracted the other quarter. So they’re saying that somehow they’re going to contract that other quarter for the same value that they have 75 percent of the volumes contracted at presently.
So it’s not looking good. FIP is a really small company. And we like looking at it because it has interesting projects, a hydrogen and natural gas blend facility, an oil terminal, a freight, coal and iron freight terminal and then this project, this export project. And this export project is the largest contributor to the company’s losses. FIP’s guiding that it’s going to go black this year due to the April contract. Again, we remain skeptical, especially given that $5 million shortfall of forecast EBITDA.
TEDDY DOWNEY: I want to take a step back here on this shipper by rail thing. First of all, it sounds so dangerous, just the whole idea of it. But I guess shipping natural gas just sounds dangerous no matter how you’re going to do it. It requires a tremendous amount of safety protocols and procedures, I would imagine. Which is kind of why I always thought the pipelines going over the mountains was always kind of a scary thing anyway.
But putting all that aside, if you had a less scary, more heavily regulated, safer rail system, would that create more of an opportunity for something like this? I mean, every story I look at about the railroads right now, it’s like ProPublica catching the trains being super long and stops holding up towns and children losing a leg because they’re trying to like crawl under the train.
DANIEL SHERWOOD: To get to school!
TEDDY DOWNEY: The lack of safety, the working conditions, not enough workers, it just doesn’t strike me as an opportunity where something like this could happen. But at the same time, we do have an issue of getting natural gas places, right? And would this be one of the things that would be helped by, if you like, you know, I saw Pete Buttigeig yesterday. Let’s just say he waves a magic wand and gets all the regulators in a row to get rail to be a safer platform for shipping, would this be more‑‑ this type of thing, will we see more of it and would it be more viable? I’m just curious to get your kind of reaction to that.
DANIEL SHERWOOD: Yeah, I mean, I’d say safer is more expensive. And the more expensive, the less likely it is of happening. I think to your point though, there’s major transportation issues as it’s related to natural gas, which I think follows based on that last word – “gas.” Matter in gaseous form is a difficult thing to transport. You know, it follows that something that’s liquid or solid is generally easier to ship. For that reason, liquefied natural gas presents some very unique hazards as far as shipping it in a pressurized, chilled container on a fast-moving railcar.
One of the most concerning aspects of it is if it gets released, it sinks because it’s heavier. And so then it sticks close to the ground. And then if it gets ignited, while I think it’s gasifying, if I understand the science behind it, it can lead to a very scary flame. So it’s a legitimate risk. And it’s for similar reasons why what happened in East Palestine, Ohio, I think, caught the attention that it did. And then the following increased scrutiny of how often derailments happen, which is commonplace. The media made it seem like it’s happening a ton now, but they’ve been happening often. What made the East Palestine incident unique was how volatile those chemicals were.
So it’s hard to say. You know, it’s hard to say. There is obviously a disparity. Why did New Fortress just pursue this in the first place? Because there’s a ton of gas in Pennsylvania. So the idea is get that where there’s a ton of gas to a facility to liquefy it, figure out how to get it to coast and then export it. This one caught our eyes because from my understanding, please correct me if I’m wrong, the only kind of onshore liquefaction facility in the country designed for export.
You know, stereotypically you send the gas to the coast. That’s where you liquefy it, put it on a ship and ship it. So there’s only one, two places, to my knowledge, in the country where small volumes of liquefied natural gas are permitted to be shipped via rail. And it’s a New Fortress affiliated entity. I’m not clear on whether or not they still have ownership in the Florida facility and then another one in Alaska. And they have all sorts of special conditions and they run the train real slow and stuff like that. So as far as, you know, there are places where it could happen. But like, do I see a world where they’re shipping liquefied natural gas by rail from North Dakota to the Gulf anytime soon? No. Sharon and Julia, do you have anything you want to add?
SHARON KELLY: Just I think the question of the railcar specifications really.
DANIEL SHERWOOD: Yeah.
TEDDY DOWNEY: And speed, it sounds like. It sounds like the tracks, the trains and the speed all need to be completely different than they are now. Which, I guess, is not really very likely any time soon.
DANIEL SHERWOOD: I don’t think it’s going to happen. And Teddy, that’s why we focus so much on permitting reform. And we’ll be discussing it again next week for our audience members that are still with us. At the end of the day, if natural gas is going to continue to be as foundational to our economy and energy complex as is modeled, we will need to figure out a way—well, I don’t know about need, but if there’s going to be a greater adoption of gas in the global economy, these constraints, these shipping constraints, will need to get resolved. I will say need, you know. And whether that’s by pipe or whether it’s going all to wind, you know, I’m obviously simplifying it. It’s a complicated issue. But it doesn’t seem like rail is the answer.
TEDDY DOWNEY: It’s always interesting. I mean, look, I think one of the things that we do is people get really hyped about a lot of different types of opportunities and technology. And there just is this weird problem with natural gas, which is like—and it feels like it’s a bit of a bomb if you put it in a container and start moving it. So it’s just got this like risk always associated with it that seems to get downplayed. And it plays out over time and everything is seeming to take longer to get your project completed, the costs get under appreciated. And so I think one of the things that we do so well is looking into how all of that actually plays out over time. Can you meet the hype? And it’s not to downplay that the importance that ultimately there needs to be a solution or a solution would be great. But that doesn’t mean there aren’t just so many challenges in making that happen so precisely.
DANIEL SHERWOOD: Yes. I mean, if you put yourself in the shoes of the molecule of methane, if you want to personify methane for a moment, what a predicament it’s in. The same thing that makes it such a good energy generator is what makes it so volatile to ship. And it can’t decide when the best moment to catch on fire is or not.
So this is a fascinating thing about technology is working with the physical nature and the scientific nature of the molecule and figuring out how to leverage that for our society. And it’s like now that we’re moving to a more natural gas-dependent economy, you know, coal from a shipping perspective isn’t going to rupture on the rail. So that’s where you see this shift. We have a lot of rail infrastructure and in some instances it’s underutilized. Well, we’re moving different commodities now, you know.
TEDDY DOWNEY: You know, the other thing I think that makes this a lot more complicated, and this kind of occurred to me—I can’t remember what I was watching. I think I was watching John Oliver a while ago when he was talking about where you need to get the electricity to in the grid. And obviously, a lot of the economic activity is on the coasts and then a lot of the generation is in the Midwest or whatever, the assets.
And part of this is unfortunate because you actually could—it would be a lot—just take a step back. If you had better regional economic activity in the Midwest, there’s no reason that shouldn’t be there. It’s partly just how our laws have been designed over the past 30, 40 years. If you had more robust economic activity, you could be using more. You wouldn’t need to be shipping it all out to the coasts.
You could actually be—I think, if we looked at policies like I remember one—I’ll stop ranting or rambling—but we’ve looked at the airline industry consolidation and the impact that that had on the flyover states, the middle of the country. And as the consolidation happened and as a lot of those hubs got taken away, as a lot of them got removed, that precipitated the decline of those regions of the country, those economic centers or those cities as economic centers. And obviously, other types of consolidation have contributed to that, where companies move locations and they go to wherever they go, they go to Texas or wherever they end up going. But there’s a lot of—it didn’t have to—it’d be a little bit easier to solve if we had more economic activity in the middle of the country, and I’m sure those people would be happy about it too. We may not have enough of a population center in some respects, I mean, because they’re not big enough.
DANIEL SHERWOOD: Yeah, I mean, the natural gas industry isn’t doing great in California, You know, like that’s a high population, high economic activity region with underlying resources that aren’t—I mean, this is a part of the kind of what’s described as the resource curse too. And then I think just last week, a large natural gas plant that was proposed to be built in Pennsylvania just got canceled. So, yeah, I mean, these are great points. And I encourage anyone to stop in Lincoln, Nebraska, if they ever can, you know. But I hear you. I hear you. It’s fascinating.
TEDDY DOWNEY: Yeah, Well, thanks, everyone. I know we went a little over, but fascinating conversation as always. I’m excited. Hopefully, maybe we can get David Khani, my colleague, to do one of these calls one day and in the future, see if we can’t corral him on here. But he might be a little sensitive right now. But we’ll see if we can make that happen. But thanks, everyone, for joining the call today. Thanks to my team here and this concludes the call. Thanks, everybody.
DANIEL SHERWOOD: Happy Friday.