Operator:

Good day, everyone, and welcome to the EON Resources Inc. Announces Fiscal Year 2024 Earnings Call on April 23, 2025. At this time all participants have been placed on a listen-only mode. [Operator Instructions] It is now my pleasure to turn the floor over to your host, Michael Porter. Sir, the floor is yours. Michael Porter: Thank you, Matt. Good morning, ladies and gentlemen, and welcome to the EON Resources conference call. I have to read the forward-looking statements before we start then I’ll turn the meeting over to management, and there will be a Q&A session at the end. This conference call includes forward-looking statements within the meanings of the Private Securities Litigation Reform Act of 1995 that involves risks and uncertainties that could cause actual results to differ materially from what is expected. Words such as expect, believe, anticipate, intend, seek, may, might, plan, and any variations and similar words and expressions are intended to identify such forward-looking statements. Such forward-looking statements relate to future events or future results based on the current available information and reflect the company’s management and current beliefs. The company’s expectations are disclosed in the company’s documents filed from time to time on EDGAR and with the Securities and Exchange Commission. Without further ado, I would like to turn the call over to the President. Dante, the floor is yours. Dante Caravaggio: Thank you, Mike. Welcome, everybody. Thanks for dialing in. Thanks for buying our stock. Thanks for your keen interest. We really do appreciate that. And I’d like to just state that this management team believes in our company. We’re all purchasers of the stock, we’re all owners of the stock, and we all believe we work for each of our shareholders. So I just want to start with that. Why invest in EON Resources? Especially look at the world market right now, you’ve got volatility in the oil pricing, you’ve got tariffs that also impact oil prices. So why look at our little company, especially when we lost money last year and we’re priced at $0.5? So I want to start with the asset itself. We purchased an asset really at originally a price of $120 million, then rejigged it to $90 million and then made an agreement with the seller to readjust it to $60 million, and it’s got 1 billion barrels in place. So it becomes our number one place to shop. And yesterday, we had a meeting internally to look at seven different acquisitions at the top of the list is the repurchase of a 10% royalty from the seller for approximately $15 million. We have a binding agreement. We have a solid choice to fund this thing. It’s going to easily be the most accretive transaction to this company and it’s already been released. So it’s in the news, you can see it out there. So 100%, one of the homeruns we’re going to hit this year is the purchase of a 10% royalty back from the seller and we’ve got the funding in place to make that happen on or before June 10. The 2024 was a story of urban renewal. We had to repair and upgrade most of the field surface facilities. We replaced 14 flow lines. It impacted a bunch of wells. We had to replace 50 pumps. We had to improve electrical. We had to buy a hot oiler to cure plugging due to paraffin and upgrade our electrical system. So now today, we have a very reliable field producing nominally 950 barrels a day with the thought that by the end of the year we should increase that by 50%. We’re working to restack our capital stack. And again, the acquisition of the 10% royalty and the elimination of $40 million in shareholder liability, $20 million of that is a seller note, $20 million of that is preferred shares that just go away and the acquisition of that royalty cost us about $20 million. So we’re going to have to pay that cash on June 10 and we’ve got in place multiple sources of funding to make that happen. Also we believe that by the end of the next couple of years we’re going to add 150 patterns, waterflood patterns in the Seven Rivers formation. And these patterns are, they look like the, the top of a Las Vegas dice number five, where in the center you have a producer and on the four corners you have injectors. So, we’ve got 95 of those working today that produce roughly 700 barrels a day. And we’ve got another 150 of those to go. In the funding with Enstream includes the funding to add another 50 patterns. So we figure of those 150 patterns we can add 50 a year. On top of that we’ve got another 200 workovers available to develop behind pipe potential. It’s taken us a while to figure out how to stimulate these wells. We had frankly three failed frac jobs using fly ash and now we’re using 20/40 sand with low temperature resin. And we’ve had a success. And we’ve got another well that we think is going to be a success. So we’ve had to walk slowly before we spend the money. And what we’re talking about here is taking workovers done by our predecessors that ran close to $0.5 million and do those for $100,000, getting essentially the same results. So it’s taken us time to really work this out. So now we think we can hit the gas with those workovers. We also published on February 26 a press release regarding our horizontal drilling potential in the San Andres where we identified 50 wells to develop another 20 million in recoverable reserves. Those wells will do 300, 400, maybe 500 barrels of oil per day. So they’re humdingers, but we’re going to be very cautious, we’re looking at our offsets, we’re learning from our competitors and they’ve been very open about best practices. So we want to say a big thank you to all those that operate near us because they’ve really opened up their books to say this works, this doesn’t work and we’re taking full advantage of that. With a drilling partner. We’re hoping to go head-to-head fifty-fifty on the drilling costs, get them to help us on the first few wells and then have at it. We’ve got 12 wells in the hopper right now to permit for drilling to commence in Q1 of 2026. And we’re planning on drilling, we think five or six wells a year for the next 10 years. We’re not going to just hit it and go and blow and that’s just so that we can be cautious and cost effective about what we do. So in summary, we expect a huge ‘26 and a much more improved ‘25. Developing the Seven Rivers waterflood to get to an eventual 250 patterns at 20 barrels a day per pattern gives us a ton of oil. The San Andreas horizontal wells, 50 wells at 300, 400, 500 barrels a day per well also gives us a ton of oil. Results from the infrastructure, repairs and upgrades, we’re seeing it now in the form of reduced decline rate. So if I’m leaving you with a message of why to invest with us in ‘24, it was a disappointment that we didn’t make more money but we did fix the field. We did negotiate with the seller, I think, a marvelous outcome to restack the capital stack which saves shareholders $40 million and we did complete engineering that pointed the way to a profitable future, which includes workovers, waterflood expansion and drilling. In ‘25, we’re going to make more oil, we’re going to cut costs. You are going to hear Jesse talk about cutting costs in our operating to where our lifting cost per barrel is roughly $23, $24 per barrel. We need to do the same kind of cuts to our G&As. So you’re going to hear a little bit about that from Mitch Trotter. And then we’re also going to make at least one acquisition in this year with frankly our own royalty of our own property. But we’re looking at more Permian properties, we’re looking at gas and we think there is lots of opportunities out there for us. In 2026, it’s going to be drilling, it’s going to be extension of waterflood patterns and it’s going to be workovers. Kind of more of the same, but just more of 2025. And with that, I’m going to turn it over to Mitch, please. Mitch Trotter: Thanks, Dante. Hello. I’m Mitch Trotter, the CFO. I want to welcome those that have been – or new to our call and those that have been on calls before. And I want to thank you for attending today. There we go. In this call, I want to give you a little insight into the fiscal 2024 results. The management team, the field team, as Dante has said, we’ve made huge strides in 2024. So at the surface level, the numbers are not so obvious, as Dante stated, but the underlying numbers reflect solid progress in the positioning for a bright future. We stabilized the field. It was not developed as it should have been. Those numbers are in our steady CapEx efforts in our balance sheet. The production was stabilized, which is reflected in the revenue results, which I’ll show you on a later slide. We’ve controlled lift or LOE cost. The LOE drop from a higher run rate in Q1 and before to our baseline now of about $700,000 a month, which has remained steady now for the last nine months. Now G&A expense did take the brunt of what we had to do to de-SPAC clean up many acquisition-related matters. In a few slides, we’ll drill down into G&A. There’s also the non-cash expenses slide that I’ve shown in the past. It does reflect our responsible hedging and also certain aspects of what we’ve done to clean up the balance sheet that is underway. Now a key aspect of our 2024 results is that the field has been making solid income from the outcome. The production growth and efforts to reduce G&A costs that will start to show up in 2025, puts EON in a good position for the future. After we drill down into the P&L aspects of this, we’ll go to the balance sheet, debt and equity. So let’s talk about revenue. So next slide, please. Many of you have been on these calls before. I did add to the slide now, the production levels, the oil prices, the split of hedging of cash versus non-cash to help you understand the numbers better. The production was stable for the year. You can see that in there, the oil revenue fluctuations was mostly driven based on the market price of oil. Now on the market price of oil, looking forward, we are hedged through 2025 at 70% or greater and $70 a barrel or greater. So do note also that in Q2, the non-cash portion – other than Q2, the non-cash portion of the hedging drove results up and down from our average of $5 million of cash revenues per quarter, which has been steady across the board. Now let’s take a look at the production impact on the P&L that Dante has been talking about. So next slide, please Again, as Dante’s been discussing and Jesse will, we’re now in the phase of developing the field now that most of the maintenance and infrastructure enhancements are coming to a conclusion. You may have heard us talk about developing the wells in the Seven Rivers waterflood. What does that mean? Average production from a well, from a frac is expected to be about 20 gross barrels of oil per day. Our recent new frac has come in at that level as Dante noted, and we’re starting on some others. So that’s good news. The cost of a workover frac is in the 150, maybe up to 250 depending on variables. So as you can see from the table that the payback period is quite good at today’s oil prices. We’ve also talked a lot about the 50 wells like Dante was saying, or increasing 1,000 barrels of oil per day. The table shows you the P&L range impact for that 1,000 impact – 1,000 barrels of oil increment, plus or minus $10 from the current oil price, I’m saying $65. Do note that the incremental change in LOE at this level of increase of production of 1,000 barrels a day is expected to be minimal because we’re already running at our base level today and it will support that extra 1,000 barrels. Now we’ve also released the study that Dante was talking about, the horizontal drilling program. And if you look on the right table, it’s – what does that mean? Well, first, the wells cost about $3.7 million to complete. Accordingly, we’re looking for drilling partner as Dante noted and they’re to share in the cost and rewards. This is quite common in our industry. And the table does reflect our study, our 50% of both. The study indicates 300 to 400 barrels of oil per day average and have also done analysis on plus or minus $10 of the oil price. And just like the Seven Rivers fracs, the payback period looks quite good. Next to the G&A slide. So please advance. So here, I want to discuss the two major drivers that impacted 2024, non-cash equity-based costs and the professional fees and this leads us into cost reductions for 2025. First, there’s $2.8 million of non-cash equity-based costs included in our G&A results. $7,000 comes from RSU options for employees, directors, which is quite normal for a public company. But as we’ve been discussing each quarter, there’s $1.6 million of equity cost for fees, settlements, et cetera, that stem from agreements and instruments for the leaseback and acquisition closing. These costs do not repeat in 2025. Also previously discussed, there’s approximately $500,000 of equity cost to clearing liabilities and cleaning up the balance sheet. Now moving on to the $2.8 million of professional fees for legal and audit. About half or $1.4 million of that stems also from the acquisition for filing, complicated instruments on the balance sheet, settlements, agreements and various other trailing legal matters. While some of these costs do carry over into 2025, we expect it will all dramatically reduce after Q2. Now I’m not going to drill down into the other areas, except I do want to note, going into 2025, there are certain cost reductions that we’ve already made beginning in January, namely, our – we have lower insurance rates in the neighborhood of $0.5 million. We’ve also reduced certain salary-related costs. So with that, I do want to go forward to the non-cash expenses. Next slide, please. So I’ve discussed with someone in the past, just like in the past here, the financial table agrees to the filed 10-K and the reference numbers for you to follow. Hitting on them quickly. Hedging, we’ve discussed G&A, we’ve already discussed. The warrant liability like in the past, stock drives the price at the end of each quarter. Derivative liability, that’s a new one that is for certain convertible notes that it all reverses in Q1 and goes away by the end of the quarter. So that’s just to pop in and out. And then number five, the forward purchase agreement, the FDA, it was terminated in November. So it reversed out all the impact during the year and has gone by the end of Q4, and the balance sheet goes to zero. We’ve cleaned it up. Financing costs, same as before, all the way since acquisition. And then number seven, the settlement of liabilities. That was a Q2 event. We picked up $1.7 million in settling certain liabilities to clean up the balance sheet. So with that, I do want to go forward to the balance sheet. So next slide, please. Now I’m not going to spend a lot of time here, but we’ll cover a little bit of debt and equity changes on the upcoming slides. But what I do want to mention is that the company has made and is continuing to make improvements to the balance sheet. The FDA contract, as I noted, liability was all cleared, Q4 gone at the end of December of 2024. Select payables and liabilities were settled during the year or cleared via equity issuance. We’ve also started the process to clean up our private loans and warrant liabilities that are current into long-term convertible notes starting in Q4, we started that process. Because cleaning up the balance sheet has always been our goal since the beginning and many of your shareholders have told us to clean up the balance sheet, which we totally agree. And so we have press releases, shareholder letters describing other actions in process. With that, I want to touch on the debt slide. Next slide please, real quickly. There’s not a real lot of change from the past. I’m not going to spend a lot of time on it. But I do want to note that the RBL or our senior debt that started at $28 million is now at $23 million based on the amortization schedule in our payments. So go to the next slide for the equity. And there’s not a lot of changes from Q3, so I’m not going to spend a lot of time on this one either. But I do want you to note that at the end of the year, we had 10 million of Class A shares and we still had 500,000 Class B shares, which are voting only rights, but it has a one-to-one conversion to Class A. And after the end of the year, all the Class B was converted. So that balance sheet item has been cleaned up and goes away. But I do want to talk in the debt side, the financing side, the funding option. So next slide please. Now here, there’s been a lot of press releases, shareholder letters on what we’re doing, our development plans, except everything takes some type of funding, whether it’s internal cash flow or other funding. Just to let you all know, we believe in a proper and balanced approach to our funding – fundraise, we are posed excessive equity dilution and excessive debt needs to be balanced. So our business – in our business, the main sources are volumetric funding, debt financing, equity instruments. Most of you know a lot about different debt instruments and equity instruments that are out there and I can sit there and go through all those options. We do listen to many proposals on some stuff that makes sense and stuff that just doesn’t make sense. We reject a lot of them upfront, because they’re just not in the best interest of the company and not in the best interest of the shareholders. So we don’t entertain those. Now instead, I want to spend a little bit of time talking about the volumetric funding, which some of you may or may not know about. And it is described in further detail if you want to read our March 20 press release. In short, it is a product – production revenue sharing instrument that is neither debt nor equity. Instead, is essentially a portion of the production and related revenues carved out to pay the investor. Once the investor makes his agreed upon return, the production and revenues revert back to the company. The payments now will fluctuate up and down with production and oil prices. That mitigates a lot of risk for the company. Certainly, our cash flow it matches. So it also minimizes or reduces default risk to the company, because it’s not a traditional one. And also, it does not dilute our common stock. Where are our plan usage? We have three of them for this year. One, field development. That’s Dante talked about the on stream, the 50 wells in that program and that’s a prime example of what we can use it for. But also horizontal drilling partner that we’ve alluded to, that’s a different version of a volumetric funding. What’s the second one? The seller consideration agreement, which we’ve talked about, it’s in the press releases. And then third, when there’s refinancing where appropriate, we may use that. So at this point, I do want to conclude my presentation. We will take questions at the end of the call and if you need a deeper dive than time may permit or it’s more detailed than is prudent for this larger group setting, just reach out to Mike Porter and he’ll schedule a one-on-one call. We’ve done several of these. With that, I want to hand it off to Jesse for the operations review. Jesse Allen: Well, thank you, Mitch. Good morning all. I’m Jesse Allen, the VP of Operations. And today, I will discuss the highlights of our 2024 operations. What we did to stabilize production and what we will do to increase production in the future, and what we’ve already initiated here in quarter one. First, though, I’d like to start off with safety. In 2024, our field operations team did a wonderful job of staying safe. We had no reportable incidents in 2024. And as part of that program, we do have weekly safety meetings in which all our lease operators come in and discuss near misses and what we can do to actually improve operations and improve the safety, although, it’s been very, very good thus far. So in 2024 highlights, when we took over the property, the daily production was basically in a free fall. And so our first order of business is what’s going on? Why is that happening? And so we started initiating procedures and work that enable us to stabilize the production at about 950 barrels of oil a day. And so what did we do? Well, first, we realized that we’re going to have to do several infrastructure upgrades that would enable us to keep our wells on production because that’s the key. You’ve got to keep everything produced into the tanks. And so what we ended up starting with, we realized that a water injection trunk line from one of our major water stations was in need of replacement. So we’ve initiated that. We also discovered that we had a lot of idle wells that were down due to flow lines that had holes in them and needed to be replaced. And so we did that type of work. And as Dante alluded, we’ve done over 20 now. And at last count, it was 25, 26 that we’ve done and that enabled us to return about 60 barrels of oil a day to production. The water injection line, that project is not quite complete, but I anticipate once we resume water injection in this part of the waterflood, that will regain about 50 to 75 barrels of oil a day. So what else did we do? Well, we actually had to do some electrical upgrades and that’s replacing some conduit, electrical wire that had been compromised. But the really big project was the replacement of a large transformer that power went to one of our water injection or water stations. We were not able to operate that particular water station at 100% capacity. And the only way we were going to be able to do that was to replace an outdated an ancient transformer that was there. And we did that. It was a big project. Now we’re operating at 100% of that water injection station. What else did we do? Well, we ended up replacing several of our horizontal water pumps in several of the water stations. We ended up swapping out a pump that was too small, used it in another water station to enable us to have a full-time injection there. That is key to our waterflood operations. We have to put water in the ground know exactly where we’re putting it and keep our rates up in order to continue to increase our production or at least maintain production. And so that’s part of what we did to stabilize the production. In addition, we purchased a hot oil unit. We use that every day and Dante alluded mainly that’s to flush out flow lines, do pressure tests on flow lines, et cetera, and so on. And that reduced our LOE about $30,000 per month over third-party use of a hot oil unit. And I’ll talk a little bit more about that as I discuss the LOE. We also produced some – also purchased several portable well testers to enable us to test our wells and have a much better idea that the work we’re doing has actually been fruitful and increasing production. So with that, let me get into LOE. From the beginning of 2024, when we took over the operations LOE was basically out of sight. It was greater than $800,000 a day or a month, $800,000 per month. We were able to reduce that to an average in 2024 of $765,000. And we’re hopeful that as we come into 2025, we’re going to be around $700,000 per month on our lease operating expense, and we anticipate even reducing that further. Next slide please. So what are our plans for stabilizing and increasing production? What have we done? As mentioned, we have been trying to figure out the formula to stimulate these wells. As Dante mentioned, we did three with fly ash. They didn’t turn out as expected. And so we’ve moved on to pumping low-temperature resin-coated sand. And what’s key about that is the past workovers and recompletions that were done, a lot of proppant was pumped. We produce a lot of that proppant back. It gets into our pumps and our flow lines. And so we had to do something different to eliminate that sand it was causing excessive well pools as a result. And so we had to do something different to eliminate that sand it was causing excessive well pools as a result. And so the last several jobs we’ve done, we pumped a low-temperature resin-coated sand, and they’ve been successful. And the first one has come in at 20 barrels of oil a day. And that’s what we expect on a go-forward basis as an average. We also are bringing idle wells back on production that had some type of downhole failure when we took over production, there was an excessive number of wells that were down for whatever reason, some of them more severe than others, and we’ve started returning those wells to production. And that again helps stabilize and increase production a little bit. In addition, as we’ve stated, our waterfloods and the injection wells are very important, and we found that there were injection wells that were down for various reasons, and we’ve returned some of those back to injection. That is an ongoing program. Finally, as what’s been really highlight is the what our technical team uncovered as far as the horizontal potential in the San Andres formation. That is – we’ve done our technical presentation. It’s on the website. You can view it there. And we’re actively seeking a partner to come in and help with the cost. And then – and so the plan currently is, we’re in the process of permitting those 12 wells and we hope to have those permitted here in 2025 with a kickoff of the first three wells toward the end of 2025 and into the first quarter of 2026. So with that, of course, we do have a Q&A at the end. I’m going to turn it back over to Dante for some concluding remarks. Dante, take it away, please. Dante Caravaggio: Yes. Thank you, Jesse. Thank you, Mitch. So guys, to wrap up our presentation here, we think we’re going to hit some home run balls in 2025, and we think that’s going to put us in position to be the best-performing microcap oil and gas company on the big board. The first one up is going to be, conclude the settlement with seller that adds $40 million in value to the shareholders. So that works out to be a little more than $2 a share. We’re going to get that done midyear. The next one up is the drilling partner. I believe we’ll select a drilling partner in the next three months. We’ve got meaningful dialogue going on with three and we’re going to cut the best deal that we can for our shareholders. The next one up is, part of the financing for the settlement with the seller is the financing to do 50 workovers, all to be completed this year. That’s going to be another home run ball. We’re going to make at least one acquisition this year. Certainly, we’re going to acquire the 10% royalty on our own field, and I believe we’ll do at least one more. And the last home run ball is to cut our G&As and our lease operating expense as much as we possibly can to weather the storm of oil prices. So that’s it. That’s kind of a five home run inning, and we think that’s going to be tough competition for our other public companies that we compete with. With that, I’ll turn it back over to Matt to start the Q&A, please. Operator: Certainly. Everyone, at this time we’ll be conducting a question-and-answer session. [Operator Instructions]. Thank you. That concludes our verbal Q&A. [Operator Instructions]. I will now turn the call over to Michael Porter for remaining questions. Michael Porter: Thank you, Matt. Gentlemen, the first question that comes up is as congratulations on your progress. What are your largest concern that might negatively impact your plans? And also, what are your plans regarding future use of stock in lieu of cash for AP and other liabilities? And the follow-up question is how is the stock valued? And is it fully registered when issued? Gentlemen, would you please answer the questions? Mitch Trotter: Let me start that one, and then I’ll turn a little bit on to – over to Dante. First, our largest concern is of course the market. Everybody has got that. Oil prices go up and down, stock prices, the market tariffs and all that, that’s everybody from Exxon and Apple down to companies like us, nobody knows what’s going on. But let me address the stock questions, and then I’ll give to Dante to talk about other concerns that he may have. Now how are we going to use the future stock for the cash for APs and other liabilities? Well, the $500,000 already talked about over half of that was settling debt that related it to acquisition, okay? The rest has been for ongoing people that are heavily invested in our company as in providing services to us in the field and through high-end consulting type arrangements. So we will use it sparingly. It’s – we’re not going to use an excessive amount. We haven’t in the past and we don’t plan to in the future. Now how is the stock value? That’s actually two different questions. One is, what is the valuation from a GAAP standpoint? And that’s just the base – that’s a GAAP thing based on the date of the grant and the stock price. But how do we value it with respect to the issue price is the bigger question, I believe in here. And we’re not giving discounts on that. It is basically either at the trading value or a little bit above what it is right now, and it will fluctuate. So that’s a game time decision each time as to what makes sense for all the parties involved, whether we just use cash or is it worth it doing that. Now these shares are not registered. They are unregistered shares. They get issued. And then the next S-1 will allow us to register them. So – and you can look in the past at all the registered shares in our S-1 filing. So that’s basically what it is with that. Dante, did you want to hit on any of your larger concerns [indiscernible]? Dante Caravaggio: Yes, I’ll just put one out there. I mean, we have a low lifting cost to $23 a barrel and if we can cut our G&As. And if we can restructure our RBL, we bring all those costs down so we can make money at $35, $40, $50 a barrel. But it also makes me want to look at gas. Gas is behaving better in the market than oil. So we may look at that, look at gas in the coming years what we can do as a hedge against a weak oil price. But my own view, and again, as Mitch said, nobody knows the future. But I see what the social costs are to the Saudis and they need an oil price that’s up there. So I think any reduction in oil price is going to be short-lived and we’ve got time on our side because we’re almost fully hedged at 70. So I think we’ve got time to react and to study and to understand what the markets are going to give us. So that’s my response. Michael Porter: Thank you, sir. The next question, are you still working on the workovers wells? Or is this less of a priority list and the Seven Rivers is a priority? Dante Caravaggio: I might try to answer that. The workovers are tied in with Seven Rivers. So some of the workovers are to add patterns. So some of the work we’re doing right now is actually adding five spot patterns. Some of the workovers are to test the San Andres with vertical wells in preparation of drilling them horizontally. So the workovers are going to be a forever top priority. I mean we’re going to be doing that for the next 10 years, which is develop behind pipe potential. We’ve got something like 10 different stacked pay horizons with names like Oceanic and San Andres and Seven Rivers and so on. So, as we learn about these pay sections through workovers, which generally include shooting holes in the pipe and doing some kind of stimulation, whether it be asset or a frac, we just have no end of fund there. Now I’ll go to Jesse, did I say that about right? Jesse Allen: Yes, sir. Yes, there’s – yes most of our workovers will be in the Seven Rivers plugging back and then adding Seven River perforations, both in producers and injection wells. And as you’ve mentioned, the vertical workovers that we have are to test intervals within San Andres. Our geophysicists has been able to identify three or four benches that we could potentially do Horizontal Wells. Our main bench is what is known as the Jackson Slaughter, which is an interval – local interval name within the San Andres section. So yes, we say 50 horizontal wells currently that could double or triple with the identification of these additional benches that we could go horizontal. So yes, the future looks very, very bright for us from a workover and/or drilling horizontal completion standpoint. So back to you. Michael Porter: Thank you. Another question. Good morning EON Team. Curious what are you guys doing to negotiate and benchmark parts, pumps and other goods necessary in order to optimize productivity savings? Jesse Allen: Dante, I think I can take that one there. Dante Caravaggio: Yes, please. Go ahead. Jesse Allen: Yes. Obviously, the Permian Basin and even where we’re at in the Northwest Basin there in New Mexico. Prices are quite competitive, and we do take typically two to three bids from vendors and not necessarily go with the cheapest, but whichever service affords us the best value. And that includes parts, services, rigs, downhole pumps, surface pumps, you name it. We do a very thorough job of bidding those costs and then taking the vendor and/or parts that provide the most value. And so we’re very, very cost conscious. You have to be in this environment, especially if we end up in a period of lower oil prices, less than $60 or $50 per barrel. Michael Porter: Thank you. Jesse Allen: Probably that answers your question. Michael Porter: Yes. Jesse Allen: Go ahead. Michael Porter: Next question. If we get a nice recovery with WTI oil at $85 to $90 a barrel this summer, would you try to increase production faster, reworking horizontal wells, et cetera? Dante Caravaggio: Yes, I’ll answer that. Yes, we would. We’re limited by the funds we can raise. And as the oil prices go up, our access to funds greatly increases as does our access to funds with the stock price. So if we have more money, we’ll accelerate workovers, we’ll accelerate drilling horizontal wells, but not ridiculously so. You’re almost a little bit limited by what can our current staff do, what lessons learned can we digest and apply to the next wells. We’ve learned from some mistakes of the past. We thought we had a winner with asset stimulations. And frankly, last year, we went too fast and made some mistakes and then just slowed it down. So the answer is yes, we’ll accelerate but not to a ludicrous speed. Mitch Trotter: Let me add to that answer a little bit because there’s another obvious question in that. If it does get to that level, we’re watching it. So the horizontal wells are all incremental. I will look at it. We will as a company, whether we hedge a little bit more, take advantage of the higher prices to lock in some future oil like we’re at $70 or greater because price was at the $85 to $90 range a year ago, and we locked it in all the way through the end of 2025, thanks to that. So something like that pops up, we’re going to take advantage, either for later parts of 2025 or going into 2026. So we watch it to make certain our hedging program is proper. So now back to you, Mike. Michael Porter: Okay. Last question regarding the $52.8 million revenue sharing of volumetric funding arrangement with Enstream Capital, is this funding deal still on track for June 2025 closing? Thank you. Mitch Trotter: Dante, can you take that one? Dante Caravaggio: Yes, I’ll answer it. So far, the lender is saying yes. And until it closes, frankly, I’m nervous. But the indications I have is that we’re still on track. If oil takes a precipitous drop, this number may reduce, and we’re just going to deal with it. We’ll just deal with it. Then we’ve got backups in place to cover the shortage. So we’re – we’ve got a backup A and a backup B and a backup C but it would sure be helpful for us to have oil prices stabilized in the 65% range or better as we head into June. Michael Porter: Okay. If you all don’t mind, I just got two more questions, so I’d like to put them out there. The first one is financing for the 50 workovers is the goal to get this done in the next two or three months? Or can you give us a time line? Mitch Trotter: I’ll answer that. It really ties into the Enstream. And part of that program has the $52 million, $53 million as just under $10 million for those 50 wells. So that’s already prearranged and it will close at the same time. And if things for some reason, work out, maybe we can do it sooner. So yes, and then we’ll kick off the program of actually doing the work, which will take a few months. Okay. Michael Porter: And one more question. With President Trump saying Drill, Baby Drill, are you seeing new drilling permits going through faster for you going forward? And what is your relationship with drilling permits with the state of New Mexico? Dante Caravaggio: Yes. I’ll let Jesse answer that. Jesse Allen: Yes. As most people probably knows the regulatory environment in New Mexico is a little tougher than Texas. And so as Dante has already said, we deal with it. And the drilling permit process is typically a eight- or nine-month process. But with the new administration, all indications are maybe that’s going to be a five- or six-month process. So the answer to that question, yes, it does look like the environment has improved for permitting. And the same goes for the workovers. So they have – because our properties is the BLM land, Bureau of land management, federal land and state land, we have to get approval typically from both agencies. And so workovers do take longer than they do in Texas, typically two to three months. And we are fighting a little bit of that now, but we’re working on relationships. And hopefully, by the time we’re funded with Enstream, those permits will be approved the work over permits. So to conclude, yes, the environment is improving, and it is probably a result of the new administration having come into office. Michael Porter: Thank you. Dante, that’s the last comment – last question. I’m turning the meeting back over to you. Dante Caravaggio: Yes. Well, I just want to say thank you to all our shareholders. We’re grateful for all of you. And we know you put your trust in us every time you buy a share, and we don’t want to betray that trust. We are very optimistic on our future. We think we’ll weather the storm, whatever it is. And we’ve got a lot of knobs to turn to as we mentioned today, to keep us on track to a very profitable 2026 and we think in the trailing quarters of this year, you’re going to see remarkable results from us. So, with that, I’ll turn it back over to Matt to wrap it up. Operator: Thank you. Everyone, this concludes today’s event. You may disconnect at this time, and have a wonderful day. Thank you for your participation.