Amplify Energy Corp. (AMPY) Earnings Call Transcript & Summary

Welcome, everyone. Amplify Energy is pleased to have them here today, to tell their story. [Technical Difficulty] on this call, I think is getting acquired. We'll have a linkup after a period of time for those who might have missed the call or who might want to review the commentary. As an introduction, Amplify is a company I initiated on in May and what we're looking for this year because, we felt macro is going to be quite challenged. We're looking for companies that were growth catalysts, we're looking [Technical Difficulty] in terms of really recurring ongoing catalyst, but at the same time, catalysts that were not recognized in the market. So we can get to [indiscernible] and then a lot of drivers to play on and Amplify has delivered to that and not only that, they are just beginning with their story. So I invited the guys today to tell their story and maybe give us some more time to discuss strategy and background in categories and segments [Technical Difficulty] on their earnings call, and with that, I'd like to give the floor to Martyn. [Technical Difficulty] questions from email or both to me personally and to your sales person so that all questions will be asked, and in most cases, I'll ask them as they're written. So Martyn, do you want to kick it off?

Yes. Great. Thank you, Subhas. I'm Martyn Willsher, I'm the President and CEO of Amplify Energy. I'm joined today by Dan Furbee, our COO; Jim Frew, our CFO; and Michael Jordan, our Treasurer. I'm going to give just a brief overview of the company itself before hopefully spending most of the time in Q&A. I don't want to spend most of my time talking kind of things that you can look up yourself but I really want to just make sure that everyone has kind of a basic understanding of what the company is. And so I'm going to move to Slide 5 of our investor deck and really just talk a little bit about the company from this one slide. So what this company is, it's not -- first of all, we're not a traditional shale oil gas play where we're constantly drilling and having to kind of stay on that treadmill of drilling. We are a diversified, mature oil and gas play where we really look to kind of utilize our capital very efficiently and in a very specific way on one or two opportunities that are the most beneficial to the overall organization. You can see, if you look at this map, we have assets across the U.S. I'm going to kind of speak about each one of them in turn. But one thing that they all have in common is that they're more mature, they are much lower decline assets than what you see from a lot of oil and gas shale players. So this means that we don't have as much money to kind of keep production relatively flat, and we utilize our capital specifically for those best opportunities, which we'll get into in just a minute, is really the kind of the focus on kind of the catalyst that Subhas was mentioning earlier. I want to start with #4 on this list, which is our East Texas position. This is our largest position by acreage. It's largely natural gas weighted. There are some NGLs and condesate out here, but largely gassy. It's a position that's essentially all held by production. So we have some opportunities here in both the Cotton Valley and the Haynesville that we're starting to look at. Obviously, gas prices have been challenged for quite some time. So we do robustly hedge on the natural gas side to kind of lock in our base production and then look at opportunities as they come along and how they might work with the gas curve that we have in place. But this is an area, like I said, where we've got this for the long term. Usually, this is an area where they have a little bit steeper declines at first, but because this is, like I said, the longer-term mature play at this point, these declines are in the kind of the low double digits or kind of right around single digits at this point for the field as a whole. So it's a -- it fits our strategy where we can, like I said, maintain the base production or to kind of be just slightly declining and then take advantage of opportunities when they come along to add production. Typically, we don't operate and drill our own wells. We like to participate. We obviously have the opportunity to drill our own well, so that's what we choose to do, but where we kind of prefer to kind of diversify our risk a little bit in this area, kind of participate in multiple wells with operators that we believe do a good job of developing. And so that's what we're doing now and going into the end of the year, we're participating in four wells, two Haynesville, two Cotton Valley wells, with a partner out there. And so those should be online kind of, call it, late Q1, 2Q of next year. Certainly looking at good returns from those based on the curve to-date. So still good opportunities despite where the gas curve is. From there, I'm going to go up to #1 on this list, which is our Oklahoma-Mississippi Line position. This is an area that we brought into the company through a merger with Midstates Petroleum 5 or 6 years ago now. It's an area where we've really focused on eliminating costs. We've moved everything pretty much that we can from ESP to rod pump. This is an area where I think it's 65% to 70% rod pump at this point. We are actively trying to, like I said, manage costs out here. We kind of try to hold this flatter through an ongoing workover program. We utilize at least 1 workover rig to kind of manage our parts, and then we utilize ESPs and rod pump conversions. This an area where there is some upside development at a certain price. It's not at the top of our list, but we do have some acreage where it would be interesting from a development standpoint. But we're very selective on what we choose to develop, and right now, this is just an area where -- like I said, it's an area where we have some inventory of upside but not an area where we would develop in the near term. Moving down from there to #5, that's our Eagle Ford position. This is the one shale asset in our portfolio. It's a non-op position. So it means we don't operate any of the wells in this area. And we have between 5% and 20% working interest depending on kind of the vintage of the wells. The older wells we have relatively a higher working interest and the newer wells, it's slightly -- it's obviously in the 5% to 6% range. It's an area where we participate when our operators develop. Right now, we are participating with Murphy on, I think it's 11 developed wells and two wells that we're refracking. The interesting thing about the refracs is that they're a lot more valuable to us relatively because we have 20% of the refrac wells whereas we only have, call it, 5% to 6% of the new development wells. So I think those 11 refracs and -- I'm sorry, 11 development wells and two refracs are about one net well to us. Those should also be coming online early next year. From there, we'll go up north to what's #2 on this list and this is something that we've talked about a lot this year. This is our Bairoil asset in Wyoming. And Bairoil is a tiny little place kind of in the middle of nowhere in Wyoming, population is less than 100. So it's really in the middle of nowhere. This is a legacy long-term CO2 flood. It's been on CO2 or tertiary flood for, I think, 40 years at this point. So it's very dependable, stable low-decline oil production scenario where we've tried to just kind of manage costs and manage to keep the profile as flat as possible over time. It's also an area where we thought about potentially divesting. We've got that asset on the market. And as of the last earnings call, what I can state publicly is that we were still in active discussions. If there's something to announce, then we will obviously announce it publicly. But we're also very comfortable holding on to that asset, if that's what we feel is in the best interest of the company. So we are -- like I said, that is an asset that has been in the market and potentially could be sold. And if there is a PSA or another reason to announce that, we will do so publicly. But as I said, in the meantime, we're obviously enjoying good strong cash flows of that asset. That brings us to #3 and kind of the most interesting asset on the list, so to speak. This is our offshore California position we call Beta. It's the Beta field. It's an area where you're combining two words that aren't used a lot in positive terms, offshore and California in the oil and gas world. But ironically, the two negatives actually make a positive in this slide, because we're in the Federal waters offshore California, which means we don't deal with a lot of the state regulations out there. We -- our production comes straight onshore and straight into the refinery complex in the Port of Long Beach, Los Angeles. And so we really just transport our oil across the Port of Long Beach into our refinery. There's no pipelines across the state of California. It's a much easier operating environment. We don't have a lot of the California regulators, we deal with the federal regulators out here. It's still an area where you have to operate very carefully and by the book, but dealing on the federal side is certainly easier than dealing the state side. The reason it's such an interesting asset is that for a long time now, this asset has been underdeveloped. It's been an area where I personally have always wanted to kind of really see what the potential is, and joined with my fellow executives here, we've made the decision last year to start developing this asset this year. In the scenario where historically, it's been developed, let's call it vertically, and there's a slide in this deck which we could look at later if we want to, where there's basically six zones that you can -- in traditional oil and gas, you drill straight through those zones and you perforate through those six zones, and you produce all six. What we've done in kind of the shale plays over the last 10 to 15 years and what is the most interesting out here is the ability to drill horizontally or laterally through these -- even the best zones and connect with a lot more of the reservoir. This reservoir is very heavy crude, which means it doesn't deplete a wide area, it doesn't move that far from kind of the reservoir, and so by drilling these horizontals or laterals through these kind of more prolific zones and an almost prolific zone out here is just called the "D Zone" nothing fancy here. By drilling these horizontals or laterals through the D Zone, like I said, you can contract a lot more of the reservoir, you can actually bring on wells that are very, very strong. And the good part about this, similar to other areas of field is that these wells do not decline like shale wells. Shale wells, you might have 70%, 80% decline in year 1, these are 30% to 40%, and they level off fairly quickly. As an overall field, it's a, call it, a 5% declining asset, which we typically are able to kind of mitigate through workovers and working on the wells. And so all of this incremental production that we could bring on can be stacked instead of getting on a treadmill where you're having to kind of constantly drill wells to kind of make up for the lost production from the shale wells that are kind of declining quickly. Out here, you can actually start to stack production and really grow it without a huge capital commitment. That's what we started to do this year. And our well we just brought on recently, we've got these wells, and we've got a type curve kind of range in this presentation. There aren't a lot of analogs to what we're doing from the past, and so we've really kind of gone with a very conservative type curve as kind of the range. Our first well exceeded kind of the high end of the range and came on with a 30-day IP of over 730 barrels a day. We're still making 650-ish roughly 2 months later. And so these wells at that range because -- the other thing to note out here is that this is a highly fixed cost area. So incremental production doesn't cost you a lot from a development perspective, and the rigs are already on the platforms. And so we control a lot of the cost of development, we control all of the cost of operations. And so if you bring on a well, whether it's at $65 or $70 a barrel oil price, you're only spending $2 or $3 of operating cost. And these wells are roughly 30 days from drilling to bringing them online. So you've got very quick paybacks. We put our payback for our well we just drilled in about 4 months. And so with a 4-month payback, you can imagine that the IRRs are well over 100%, the PV of these wells are multiples of the capital that you're committing to them. And so it's a huge potential to once again kind of stack production on top of each other and really meaningfully impact the future free cash flow potential of the asset and the company as a whole. So we drilled the first one. Like I said, that had about a 4-month payback at kind of the production levels we were seeing. We are drilling wells -- the next two wells and now built beyond before our next earnings call. So we'll be able to update the market at that time. And so those are -- that's a really exciting program. One thing I'll note is when you look at our reserves, there are -- first of all, we only have four wells in the PUD category for this Beta field that are in our reserves, and they're all at that lower type curve that I mentioned earlier. To the extent that we continue to see substantially better than that from a productivity perspective and if we continue to see the strong results, we have the ability to add a substantial number of PUDs into that development program and into our reserves that are currently not booked anywhere. And so that would really change in a material way, kind of the value and the reserves associated with this asset going forward. And so that's one of the things I mentioned in our last earnings call is that we don't have all of these PUDs kind of built into our -- SEC rules are very strict about how quickly and when you can put reserves on. But with the success of the program that we've already seen and hopefully we'll continue to see, we have the ability to potentially add a significant amount of reserves because there's really nothing preventing us from drilling a lot more wells out here, and like I said, growing production substantially. That's really been the primary catalyst for this year is the ability to grow our free cash flow through these incremental wells. And I said we've got the first one on, hopefully, two more on before we announce Q3 earnings. And like I said, that should be a really big and significant impact to our stock price going forward as we start to demonstrate the value potential of this field. I think that's probably most of it. I think there's one more thing I'd like to mention. One of the things that we focus on a lot around here is cost. Obviously, with more mature properties, you're always constantly fighting kind of the cost creep and we've seen inflationary effects of the last few years. One of the things we've done to mitigate that is by creating our own service company just to service our own assets. This allows us to not have to compete in -- especially in an area like East Texas, where you're competing a lot of -- against a lot of large Haynesville producers, for example. So our -- we can do a lot of our own slickline work. We do a lot of our own core compressor work. We have -- we actually have water hauling trucks. So all of this is done in order to allow us to control our costs and kind of mitigate kind of the challenges of competing against other service providers. We are not trying to be a service provider for everyone else. This is really just designed to manage the cost structure for the company as a whole. But for a fairly minimal capital investment of between $1 million and $1.5 million, we're already at a run rate of $2.5 million to $3 million a year from those activities. And we expect to be able to continue to grow that and utilize that to really offset. We consider that kind of an offset to operating costs. And as you kind of look through our presentation, you'll see a lot more detail on that as well. And Subhas, with that, like I said, I want to kind of introduce the overall organization, but happy to kind of start taking questions for myself or the rest of the team.

Yes. Terrific. Thank you. So just to remind that the Internet might go in and out a little bit, but if that's the case, I can e-mail the questions as well. So let's start with Beta. What do you think sort of the -- the field, I think, have peaked to 20,000, 21,000 barrels per day, something like that way back, right? You're in the mid-3s right now. And if you sort of look at field potential and inventory, could you kind of frame for us what the field capacity is? Not maybe what your plans are at this time, but maybe what you think the field is capable of?

Yes. And I'll let Dan answer from his perspective. But if everything was perfect and we started drilling big wells and kind of stacking them, there's no reason you couldn't get back to that similar level of production from a purely operational perspective. Obviously, that will take the required investment. This was -- these platforms were built by Shell, and they were well built. There's a lot of redundancy in a lot of the operating systems. And so that's certainly kind of about the max volume. And obviously, that's on a gross basis because I think we're obviously making more than the mid-3s from -- or low-3s from a gross perspective because we have a 25% royalty. So we have a lot of room to run now is really the answer to the question. And certainly, we're not in any -- that would be a great problem to have if we're running into the field limitation issues. Because that would mean we had at least quadrupled production. So we've got a lot of way to go. Dan, do you have anything else?

Yes, that really summed up well. I mean, the platforms were developed to produce over 25,000 barrels of oil a day back in the 80s. Nothing has really changed. We've actually expanded some of our capacity on the water handling side and other facilities in the platform. And then we have plenty of empty slots to drill more wells and existing wells to sidetrack out of, which is what we're doing now from wells that have been depleted already or wells that we're re-purposing that are low producers to drill horizontal soft load to access certain parts of the reservoir. So no constraints in terms of growth at the Beta field from facilities or otherwise.

No, all I was going to say was I think you know when...

When you look at the inventory that you have, right, can you give us a sense -- I don't know if you could -- yes, can you give us a sense of the sidetracks potential? How you evaluated them, how many of the wells are side trackable? And maybe the number of total slots and the number of empty slots for new wells? And if and when you were going to begin a new well development program, what would trigger that?

Yes. Let me start before we -- so we're not really able to -- we're not going to delineate just yet how many we're going to drill from existing wells versus slots with conductors and slots that are just kind of wide open. I think in the near term, every well that we will be drilling will be what's considered a sidetrack, call it out over the next 4 to 5 years of drilling, depending on how fast you go. So we certainly have plenty of slots for them just -- and that's obviously the cheapest way to go. If you can drill from a well that's either no longer producing or minimally producing, then that's -- you don't have to kind of -- you don't have to spend as much money upfront and so it's the cheapest way to do it. And certainly, kind of our next few years of drilling, that's kind of the idea is to use those first. After that, we do have a number of slots with conductors already set and a number of open slots as well. And so we're going to -- as part of our kind of end-of-year process as we're working to kind of lay out the plan for 2025 and beyond, we're going to provide a lot more detail on kind of exactly how all that works, and kind of the inventory of slots and kind of the inventory of well locations as well. But as I said, I don't want to get ahead of that. But the near -- the important thing is near term, everything is going to be what's considered a sidetrack because like I said, that's the cheapest and the easiest way of kind of accessing these reservoirs.

Got it. Okay. Then when you look at the sidetracks, are you completing these wells than Shell did back in the day, any tweaks there? And is it all without control at this point that you're working like more -- is there -- do you even need seismic or have legacy seismic that's going to keep working [Technical Difficulty]?

Yes, sure. Yes, a few things there. The way we're developing them now is quite a bit of the way Shell did in the '80s. I mean I would say the biggest difference between the '80s and now is a lot of the reserves remaining are in places that the technology back in the 80s didn't really allow to reach because we have stationary platforms we're drilling from. So we have two platforms. We have rigs built into them, that Shell build in the '80s. And where we're accessing now are extended-reach laterals. And we're using kind of best-of-class tools from Schlumberger and Halliburton and all the major players to drill these extended-reach laterals. Really wasn't able to do that in '80s. And by doing that, we're hitting these reservoirs and super reservoirs, like Martyn said D-Zone, at close to 90-degree angle, so more or less horizontal wells. As opposed to Shell, they drilled wells in parts of the reservoir that were closer to the platforms they built, and they were intersecting the reservoirs at basically vertical or maybe up at 30-degree angle. And they complete each of the sands from A sand all the way through the E or F sand, in some cases, has basically vertical wells, completing them in a different gravel pack technology that wasn't -- that is different from today and producing the wells that way. So we're trying to contact as much as the best part of the reservoir as possible through one horizontal well and doing openhole gravel packs, which is kind of the best same control methodology to deliver the best deliverability as well. So that's kind of a difference in the well designs. One is for necessity because to reach the parts of the reservoir that Shell couldn't, we have to do it differently and also technology is much better in terms of these types of gravel pack jobs. Second part of the question around seismic. So we have so many penetrations through this structure here, it's very well defined. So we don't need additional seismic any new reprocessing from the stuff done back in '80s to really have a great idea as to where the best oil is, where the remaining oil is, where the lowest known oil is and all those types of things. And all the faults in this field and everything, the boundaries are very well defined. So from a reservoir standpoint, it's very low risk in terms of the development here.

Excellent. Can you give us some light on the impact of the electrification of the facilities in Beta? Are you done with the project and what are the savings?

Yes. Well, the schedule on the project, like we said, we should be finishing in the fourth quarter. We're very close to finishing it. It's been a multiyear project, a project that was needed to meet the South Coast Air Quality District in Southern California in which we need to eliminate our NOx emissions. And up until this point, we've been buying emission credits for our NOx emissions ever since for probably 20 years now in the assets. Those will go away. That will be one part of the big savings once this project is completed. And then also another part of it to get there, we increased the amount of electricity we can access from the shore. So we generate some of our power on the platform through large generators, which use diesel fuel or natural gas. And then we also pull power from an underground table from the shore, from the local utility to the platform. So a big part of this project is increasing the amount of power we can source from the shore, and that will reduce the amount of power we need to generate on the platform. And after we're done, we're expecting to be able to generate most of the power from our generators using the natural gas we produce from the platform and be able to shut down the diesel generator, which is what we use. So yes, cost savings will be pretty significant just from the elimination of the credit purchases and elimination of the diesel usage for our production operations.

Yes. We've talked about them being in the range of $6 million to $8 million a year. Some part of that, we're already seeing because you get some of it as you kind of go, we've already eliminated a meaningful amount of the diesel purchases. But we still got -- we're still -- there is more to go as we finish up the project here in the next, call it, 1.5 months, 2 months. And then the NOx credits themselves will be obviously eliminated as well, which those two things alone, like I said, $6 million to $8 million of savings. So the project has been a multiyear project that we've been doing the engineering on and whatnot for years and really over the last few years, it's been a big capital drain to kind of get it done. But it will be paid -- that will pay itself back over 3 to 4 years. And then at the same time, it sets us up for kind of a long term with this field in terms of having a lower -- our costs are fixed. So you want kind of that fixed cost base to be as low as possible. And so you've got that much more incremental operating leverage as you're bringing on that incremental production and all that goes straight to the bottom line, it will drive down your cost per barrel and at the same time, really all that cash goes straight to your bottom line.

Excellent. So as you sort of look at a model since the pandemic, you've got California with these ROCE. So can you sort of review return on capital framework? How you're looking at your priorities over the next 12 months? And how those priorities might change, if at all, from what you've been maybe looking to do in '23 entering '24 versus '24 entering '25?

Yes. I mean -- so prior to the pandemic, this was a return of capital company. Since then, we've had a couple of things change. But overall, we'd like to get back to returning capital to shareholders obviously, at the right time. And so that is something that we're going to be looking at in '25. How we're going to do that is really going to be market driven at the time, and I don't want to kind of get ahead of myself or my Board in trying to say exactly how we're going to do that. But we'll look at whether that's a dividend and some kind of buyback program, some combination of both, we'll be looking at that, like I said, closer to the time. In the meantime, obviously, with the capital, not having to spend as much capital, like I said, on this infrastructure project will allow us to really start growing our free cash flow, especially in the Q4 or retain free cash flow is what I should refer to it as. And then we are -- as I said, going into 2025, we'll have flexibility about how many wells we want to drill, let's say, in California, and we may make that a little variable depending on where oil prices are. These wells will pay back quickly regardless of oil price unless oil prices completely fall off a cliff. But at the same time, we'll think about the overall corporate structure, our hedging position and think about how much we want to hedge -- I mean, I'm sorry, how much we want to drill relative to where the market is as we get into 2025. So we'll have some flexibility to make sure that we're kicking off with good amount of free cash flow, and we'll determine the best use for that, as I said, over the last few years, it's been all gone to reducing debt, which has gone down substantially over the last couple of years. So going forward, we're going to have a lot more flexibility as we -- like I said, that debt number should be coming down here in Q4 and beyond, and we can, like I said, utilize our free cash flow in a different way as we get into 2025.

Can you review the -- I think there's some bank rules there of some sort of leverage ratio minimally that you have to achieve in order to bestow a dividend. Can you sort of review of the path to that trigger?

Yes. So the credit facility we had in place or we put in place last June, one of the restrictions are we're not allowed to do any kind of return of capital unless we have 30% capacity remaining pro forma for any distribution we make, right? So the net of that is, we've got $135 million in commitments. So if you have that 30% capacity, you have to have net debt of approximately $95 million pro forma for any distribution or return of capital you decide to do.

Okay. Is your intention to get that to 0?

No, I think, like I said, I'm very comfortable between, call it, 0.5 turn and 1 turn of leverage. I think that's kind of the sweet spot for total enterprise value. And so that's kind of where we tend to be or would like to be. And that's obviously kind of where we're heading. I said this year, kind of through the first 3 quarters, we've been signaling this all year is that most of our capital and spending is kind of in that first 3 quarters of the year and then it should lighten up in Q4, and that's where you'll really start to kind of see the free cash flow start to ramp up. And if these new wells come on like we expect, then going into 2025, you'll be in a much different free cash flow environment than you've been in for the first 3 quarters of '24. And so that will give us, like I said, that flexibility. That debt number will drop pretty quickly and then you can start talking about what you're going to do with that other cash flow.

Linking all these stuff, I'm curious how you think about -- one of the thoughts is that you're fairly liquid for a company your size in terms of dollars per day of trading volume, but that's a number that I think some of the traditional funds would love to see even bigger over time, and how that might compete with the buyback program, right? If there is a -- I don't know if there's a way to do both. But if you -- how are you thinking about that?

Yes. I mean I think from our perspective, I don't know how much of a material impact that will have, to be candid. And if we're doing the right things, we always like to say in the environment if we're doing the right things, if we think we're undervalued and we're buying back shares, ultimately, that's going to be the best return for our shareholders. So there is the counterargument as well, but in our mind, if we're able to buy back shares at a discount, that's something we should really be doing.

That's a pretty firm answer. Great. In your -- when I take a look at, I guess, your Oklahoma assets, more interesting things happening, I guess, in the Western Anadarko, and I'd say nontraditional skilled staff, you are not there out there obviously but as we took at the balance of your portfolio, where would do reinvest outside of California? I mean, it seems like you have the non-op on the gas front, but do you have -- did you have bold ambitions that pandemic cut short in some of these basins that you want to revisit one you are more liquid, which it seems like it's almost an imminent scenario for you?

I'll start, and Dan, feel free to jump in. We're very cautious. Like I said, we took a long time planning California before we kind of jumped in to do it. And with Oklahoma, we have several opportunities, but that is a very statistical play. And if you're going to drill it, you're going to have to drill kind of -- we need to be ready to drill at least 5 to 10 wells in my opinion. And so it just hasn't risen to the level yet of where we're ready to kind of make that kind of commitment. Obviously, it's not all oil as well. There's a pretty good chunk of gas and NGLs that come with those wells. And so with where commodity prices are, I think you'd want to feel pretty good about where all three commodities were and if you kind of commit to a program of that size in that area, like I said, they just -- right now, it doesn't compete with -- for capital against California, which with rates of return over 100%, the kind of paybacks. So if you were limited in California for some reason, then really you were just kind of flush with cash, certainly, you could look at it. But like I said, we're very disciplined as well. And we're not going to do it just to kind of go spend money or we're only going to do it if it really makes sense from a shareholder perspective because I'd rather give it back to the shareholders. If I'm not completely committed to the program and feel really good about the program, then I'll just give it back rather than trying to kind of spend it on something just to spend it.

Yes. And I'd say in our last earnings call as well, we talked about outside of Beta, East Texas, as the Haynesville play moves to the west, we're seeing it move towards an area where we have a decent size of Haynesville position. So I think that's a potential, especially in a higher gas price environment. There are some very good Haynesville wells being drilled in this Western part of the Haynesville play, whether that's developed through with a partner or with ourselves going out and a drilling in East Texas, I think that's something to look forward in the future potentially. And then yes, as Martyn said, in Oklahoma, certainly opportunities, and we are seeing some activity in that area, but it's limited at this time. So we didn't look at it, but also in Oklahoma, East Texas and especially oil, I think there's investments could be made in the future, just on the cost savings side that we're keen to look at as opposed to just pure drilling.

Yes. To that point, right, I mean, that's really like magnify -- that's the investment opportunity to magnify that Martyn mentioned upfront. So it's not big dollars, they can be impactful. And I think that's where we see the opportunities to invest in the service business in East Texas, and potentially Oklahoma build that out, continue to drive costs down. I think Subhas, we probably should talk about, in both East Texas and Oklahoma, there's a lot more fragmentation than some of the other areas where we operate. So there are opportunities to kind of do bolt-on acquisitions at some point in the future, if we could do it at the right deal terms and then kind of leverage the existing infrastructure you have in those areas to lower those costs. So those are the kinds of things I think we probably see as most exciting as it relates to those two assets today.

California I think when you sort of your introductory comments, you said offshore and California were not top of mind for us. But since you had that unfortunate accident back then, could you just kind of review the steps that have been taken by the regulatory authorities out there to sort of prevent this from happening again, which if you want to review the story, I mean, obviously, no fault of your own, but maybe the way that even those events might have been de-risked?

Yes. I mean I can spend quite a lot of time on this, but I'll try to give you the quicker version for those that aren't familiar with the story. So back in October '21, there was a leak from our pipeline. As it turns out in January of that year, two of the probably top 10 largest cargo ships in the world, both hit our pipeline or actually stuck on our pipeline, dragged our pipeline and bent it kind of out of shape. It's kind of a testament to the strength of the pipeline that despite getting dragged to 150 feet that it didn't actually rupture. It bowed, but it didn't break. And so the really, really unfortunate thing is that what those ships and what the people monitoring the ship should have done is make sure to notify us to make sure notify the Coast Guard and notify everybody that this incident occurred because they knew it. But nobody -- that didn't take place. And so this was -- this happened during a high wind event that happens offshore California sometimes. And so the rules that were in place for that those cargo ships were supposed to be basically have their engines on and be ready to move. That didn't happen, and that's why they dragged their anchors over this pipeline and moved it the way they did. So there was a series of failures there in terms of how -- so unbeknown to us, this incident occurred. And so 9 months later, over time, if you got a bow in your pipeline and you're running through it with pressure, it wore just a very tiny crack along the in-seam kind of right kind of where you make the turn, right on that in-seam of that pipe where it was supposed to be straight, and now it bowed, and that's where the crack occurred. So we've replaced all of that pipeline. It's all straight and cleaned up. But from a regulatory perspective, the way that they're now handling the boats in the Port of L.A Long Beach has changed completely since that time. During that time when this happened, this is during that time when the supply chain crisis was kind of at its worst, there were probably 70 boats kind of lined up offshore. And so they were using anchorages that they've never used before. They were just -- it was kind of a mess in those port areas. They now have everyone basically out at sea and there's kind of a minimal number of boats allowed near the shore. They're also no longer using the anchorages that are near our pipeline. But most importantly, in my opinion, not only are they not using them. If there is a weather event, then not only do you have to have your motors on, you're actually told to leave. So when there is a weather event kind of in that area, the people monitoring the ships, which is the Marine Exchange of Southern California, they're actually telling the ships to leave the port complex, and basically, so they go -- they not only turn their motors on, they actually leave the area. And so the risk of having another event where somebody is not doing what they're supposed to be doing from a pilot perspective in there, they allow their ship to basically drag anchor during a high wind event, has been minimized. We also have much better communication between all of us. If there is any kind of weather event, we're communicating with them, we understand kind of what they're doing, what they're advising the ships to do, they'll notify us if there's anything unusual. It's -- like I said, it's been -- I think communication has been one of the key changes in addition to a lot of the changes that they've made in terms of how they manage the ships during an event like this. And so it was very unfortunate. It's one of those things where, like I said, it's not a lesson than any of us would want to go through again. And I think from our perspective, their perspective, from the Marine Exchange of Southern California's perspective and from the shipping industry, I mean they ended up reimbursing us for a lot of our out-of-pocket expenses. They had huge expenses to our insurers, to various constituencies out there as well. So they spend a lot of money on this. Obviously, these are fairly large balance sheets on the shipping industry, but a lot of their insurers had to do it as well. So there's been a lot of changes there as well driven by the insurance market on the cargo ships themselves. And so I feel like we're all had an unfortunate lesson to be learned there, but I think there's a -- one of the other things is that in the course of doing this, we've tested this pipeline in ways that it's supposedly an older pipeline, but this is one of the cleanest, most well-maintained pipelines you've ever seen. It's extremely strong. We haven't had any thickness loss on that particular pipeline in the 10-plus years that we've owned it. And so that pipeline is going to last a very long, long time as long as nobody from the outside hits it. And so by mitigating that risk, I feel like we're -- like I said, I feel very good about the fact that we don't have -- once you bring that oil in via that pipeline, you're straight into the refinery complex. So you don't have onshore pipelines or you're dealing with a bunch of the state of California like some of our neighbors to the north in the Santa Barbara area. So this is a completely different setup. And like I said, it's actually much more streamlined and easy for us than that. So I feel very good about it. But like I said, it was a painful lesson for all the groups involved.

Can you just review your sinking fund requirements? And I think you made some improvements to that maybe on the first quarter call. Just kind of run through that quick?

Yes. So historically, we've got a -- basically, we've got a sinking fund to take care of the long-term decommissioning. One of the things that the drilling does in addition to, obviously, bringing up near-term free cash flow is it extends the life of this field substantially. And so this field is going to be around for 30, 40, 50 years to come at least. And so we are putting cash aside for the future decommissioning in conjunction with our surety providers. We have a risk management policy that basically provides us -- will essentially take care of the decommissioning if there's any kind of abrupt event. But in the long term, we're setting aside basically $8 million a year for the federal portion of the pipeline and $1 million a year rounded for kind of the state and kind of piece of the pipeline. So it's -- I'm sorry, $8 million a year for the pipeline and the platforms and then $1 million a year for the state portion of the pipeline. So long term, we're going to have this thing fully funded in cash. But like I said, in the meantime, if there was ever kind of any kind of an abrupt event, we also have it covered through kind of an insurance product that we put in place. And so we feel very good about our risk management policies, not just kind of in our sinking fund. The combination of the two covers us both in the near term and in the long term. And that, like I said, we expect to be at $9 million a year essentially into this -- basically, it's our bank account, but it's obviously set aside as kind of a restricted account for the long-term decommissioning of the asset.

And so just kind of piggybacking to what Martyn was saying, right, I think you're alluding to this. This year, that number was supposed to go up to $16 million. But because of some of the work we did on the insurance side and because of the plants that drill and extended life, the surety providers allowed us to reduce that from $16 million to the $9 million that Martyn was mentioning. So that's $7 million of free cash flow is available to us for other activities. That was a big win that happened in the first quarter.

Yes, no question. As we're sort of getting to a top of the hour, one of the things I was just -- since I wasn't looking at California market that closely, but one of the things that was really stood out was the [Technical Difficulty] out there. And can you just sort of review that? Your netbacks are exceptional. And so how we should be thinking of the variability in that? Like is it WTI Brent, the marker out there I think [Technical Difficulty] that as well?

Yes. I think you broke up a little bit, but I think the question is about netbacks in the kind of California marketing. But so since California is -- and hopefully, maybe this isn't known to many, but California is kind of an energy island especially from an oil perspective. You can't bring oil in from the Lower 48 into California. So all that oil for California, and they have all their special processing names, they have -- so all that oil that comes from existing California production, Alaska where it's brought in from overseas, there is no kind of -- you're not getting Permian Bakken oil into California. And so from a -- you're not competing against those areas, you're competing against the Middle East or Ecuador, in the old days, Venezuela. And so those are kind of what you're competing against from a barrel perspective. And so it moves in conjunction with Brent. And so kind of as the WTI and Brent differential moves around the, what we call -- it's called Midway-Sunset, move in conjunction with that Brent price. So if the spreads flow out, then we'll stay in line with Brent; if not, more so than WTI. I think we kind of -- everyone still prices it, you kind of look at like the correlation to WTI and as long as the spread is not moving around too much, you're fairly consistent. But as I said, I actually think this is an area of actual opportunity because California's production, they are importing more oil now than they ever have in their entire history. Despite demand took a small step down post pandemic out there because of work from home. But it's really kind of leveled off and demand is still where it needs to be, but California's production is shrinking significantly. And so you're competing against, like I said, these barrels that have to be shipped in from overseas. And so you're actually stronger for that because you're obviously right there and you're able to provide the oil straight into the refineries. So that's what allows you to get the better netbacks is that your proximity is and who you're competing against is actually much better than what -- if you were trying to compete against Permian barrels going west or Bakken barrels going west.

Yes. The other thing to add on top of that, which is good, which is from a local perspective, we have a long-term relationship with the buyer that we've been sending our barrels to for a long time, but we're also connected to several other refineries right there onshore. So there's a lot of other options. So in terms of do we feel good about that, yes, I think we do because there are other options that would also be in line to take our crude if we had to go that route.

So gentlemen, thank you very much. I mean, as I hear your -- some of your announcements today and the Q&A, I'm probably even more excited about the second half of the year. I can't say that for the general shale player and it looks like these [Technical Difficulty] on a quarterly basis. Thank you very much for your time today. I don't know if you have any last words. We'll have a replay posted for those who couldn't make it today and we look forward to hearing your third quarter update in October, early November.

No, I just want to say thank you for everyone for participating today. And Subhas, thank you to you for hosting today. We really appreciate it. And if there's any follow-up questions, obviously, they can go through you, but we're always available to answer follow-up questions or set up a separate call as well if there's additional questions.

Thank you, Martyn. Thank you, everybody.

Thanks, guys.