Good day, everyone, and welcome to the EON Resources Inc announces Fiscal Year 2024 earnings call on April 23rd, 2025. At this time, all participants have been placed on a listen-only mode. If you have any questions or comments during the presentation, you may press star one on your phone to enter the question queue at any time, and we will open the floor for your questions and comments after the presentation. If you're listening on webcast, you can submit a question by clicking on the Ask Question button on the left of your screen. Type your question into the box and hit the Send button to submit your question. It is now my pleasure to turn the floor over to your host, Michael Porter. Sir, the floor is yours. 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 in 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. With further ado, I would like to turn the call over to the President, Dante. The floor is yours. Thank you, Mike. Welcome, everybody. Thanks for dialing in. Thanks for buying our stock. Thanks for your keen interest. We really do appreciate that. I would like to just state that this management team believes in our company. We are all purchasers of the stock. We are all owners of the stock, and we all believe we work for each of our shareholders. I just want to start with that. Why invest in EON Resources? Especially look at the world market right now. You have got volatility in the oil pricing. You have got tariffs that also impact oil prices. Why look at our little company, especially when we lost money last year and we are priced at half a dollar? 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. It has a billion barrels in place. It becomes our number one place to shop. 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 is going to easily be the most accretive transaction to this company. It has already been released. It is in the news. You can see it out there. 100%, one of the home runs we are going to hit this year is the purchase of a 10% royalty back from the seller. We have the funding in place to make that happen on or before June 10th. 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. 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 are working to restack our capital stack. Again, the acquisition of the 10% royalty and the elimination of $40 million in shareholder liability, 20 of that is a seller note, 20 of that is preferred shares that just go away. The acquisition of that royalty costs us about $20 million. We are going to have to pay that cash on June 10th, and we have in place multiple sources of funding to make that happen. Also, we believe that by the end of the next couple of years, we are going to add 150 waterflood patterns in the Seven Rivers Formation. These patterns look like 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. We have 95 of those working today that produce roughly 700 barrels a day, and we have another 150 of those to go. The funding with OnStream includes the funding to add another 50 patterns. 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 2040 sand with low-temperature resin, and we've had a success. We've got another well that we think is going to be a success. We've had to walk slowly before we spend the money. What we're talking about here is taking workovers done by our predecessors that ran close to $500,000 and do those for $100,000, getting essentially the same results. It's taken us time to really work this out. Now we think we can hit the gas with those workovers. We also published on February 26th 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. They are humdingers, but we are going to be very cautious. We are looking at our offsets. We are learning from our competitors, and they have been very open about best practices. We want to say a big thank you to all those that operate near us because they have really opened up their books to say, "This works, this does not work." We are taking full advantage of that. With a drilling partner, we are hoping to go head-to-head 50/50 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. We are planning on drilling, we think, five or six wells a year for the next 10 years. We are not going to just hit it and go and blow. That is just so that we can be cautious and cost-effective about what we do. In summary, we expect a huge 2026 and a much more improved 2025. 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 Andres 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 are seeing it now in the form of a reduced decline rate. If I'm leaving you with a message of why to invest with us, in 2024, 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 saved shareholders $40 million. We did complete engineering that pointed the way to a profitable future, which includes workovers, waterflood expansion, and drilling. In 2025, we're going to make more oil. We're going to cut costs. You're 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&A. You're going to hear a little bit about that from Mitch Trotter. We're also going to make at least one acquisition this year with, frankly, our own royalty of our own property. We're looking at more Permian properties. We're looking at gas, and we think there's 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. With that, I'm going to turn it over to Mitch, please. Thanks, Dante. Hello. I'm Mitch Trotter, the CFO. I want to welcome those that have been on the New York call and those that have been on calls before. 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, have made huge strides in 2024. At the surface level, the numbers are not so obvious, as Dante had stated. The underlying numbers reflect solid progress and 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 dropped 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 expenses did take the brunt of what we had to do to despack, 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. It also shows 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 outgo. 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. Let's talk about revenues. 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. 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's been talking about. 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. That is good news. The cost of a workover frac is in the $150,000, maybe up to $250,000, depending on variables. You can see from the table that the payback period is quite good at today's oil prices. We have 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 barrels of oil increment, ±$10 from the current oil price, I am 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 are 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. If you look on the right table, what does that mean? First, the wells cost about $3.7 million to complete. Accordingly, we're looking for a drilling partner, as Dante noted. They're to share in the cost and rewards. This is quite common in our industry. The table does reflect our 50% of both. The study indicates 300-400 barrels of oil per day average. I've also done analysis on ±$10 of the oil price. Just like the Seven Rivers fracs, the payback period looks quite good. Next to the G&A slide, please advance. Here, I want to discuss the two major drivers that impacted 2024: non-cash equity-based costs and the professional fees. 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. $700,000 comes from RSUs, options for employees, directors, which is quite normal for a public company. As we've been discussing each quarter, there's $1.6 million of equity costs for fees, settlements, etc., that stem from agreements and instruments for the despac and acquisition closing. These costs do not repeat in 2025. Also previously discussed, there's approximately $500,000 of equity costs 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 of agreements, and various other trailing legal matters. While some of these costs do carry over into 2025, we expect it'll 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, we have lower insurance rates in the neighborhood of $500,000. We've also reduced certain salary-related costs. With that, I do want to go forward to the non-cash expenses. Next slide, please. I've discussed with someone in the past, just like the past here, the financial table agrees to the file 10-K and the reference numbers for you to follow. Hitting on them quickly. Hedging we've discussed. G&As 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. That's just a pop in and out. Number five, the Forward Purchase Agreement, the FPA, it was terminated in November. It reversed out all the impact during the year and is 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. 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. With that, I do want to go forward to the balance sheets. 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. What I do want to mention is that the company has made and is continuing to make improvements to the balance sheet. The FPA contract, as I noted, liability was resolved, 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. Many of you shareholders have told us, "Clean up the balance sheet," which we totally agree. We have press releases, shareholder letters describing other actions and 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. I do want to note that the RBL, our senior debt, that started at $28 million, is now at $23 million based on the amortization schedule and our payments. Go for the next slide for the equity. There's not a lot of changes from Q3, so I'm not going to spend a lot of time on this one either. I do want you to note that at the end of the year, we had 10 million of Class A shares. We still had 500,000 Class B shares, which are voting-only rights. It has a one-to-one conversion to Class A. After the end of the year, all the Class B was converted. That balance sheet has been cleaned up and goes away. I do want to talk on the debt side, the financing side, the funding options. Next slide, please. Now, here, there's been a lot of press releases, shareholder letters on what we're doing, our development plans, etc. Everything takes some type of funding, whether it's internal cash flow or other funding. Just to let y'all know, we believe in a proper and balanced approach to our funding fundraising. We are opposed to excessive equity dilution and excessive debt. It needs to be balanced. In our business, the main sources are volumetric funding, debt financing, equity instruments. Now, most of you know a lot about different debt instruments and equity instruments that are out there. I'm not going to sit there and go through all those options. We do listen to many proposals on some stuff that makes sense and some 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. We don't entertain those. 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. It is described in further detail if you want to read our March 20th press release. In short, it is a product production revenue sharing instrument that is neither debt nor equity. Instead, it 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. It also minimizes or reduces default risk to the company because it is not a traditional loan. It does not dilute our common stock. Now, where are our planned usage? We have three of them for this year. One, field development. Dante talked about the on-stream, the 50 wells in that program. That is a prime example of what we can use it for. Also, the horizontal drilling partner that we have alluded to, that is a different version of volumetric funding. What is the second one? The seller consideration agreement, which we've talked about. It's in the press releases. Third, when there's refinancing where appropriate, we may use that. At this point, I do want to conclude my presentation. We will take questions at the end of the call. If you need a deeper dive and 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. Thank you, Mitch. Good morning, all. I'm Jesse Allen, the VP of Operations. Today, I will discuss the highlights of our 2024 operations, what we did to stabilize production, 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. 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. In 2024, 2024 highlights, when we took over the property, the daily production was basically in a free fall. Our first order of business is, what's going on? Why is that happening? We started initiating procedures and work that enable us to stabilize the production at about 950 barrels a hole a day. What did we do? First, we realized that we were going to have to do several infrastructure upgrades that would enable us to keep our wells on production because that's the key. You got to keep everything producing to the tanks. 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. We have 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. We did that type of work. As Dante alluded, we've done over 20 now. At last count, it was 25, 26 that we've done. That enabled us to return about 60 barrels of oil a day to production. The water injection line, that project's not quite complete, but I anticipate once we resume water injection in this part of the waterflood, that we'll regain about 50-75 barrels of oil a day. What else did we do? We actually had to do some electrical upgrades. That's replacing some conduit, electrical wire that had been compromised. The really big project was the replacement of a large transformer that power went to one of our water injection, our water stations. We were not able to operate that particular water station at 100% capacity. The only way we were going to be able to do that was to replace an outdated and ancient transformer that was there. We did that. It was a big project. Now we are operating at 100% at that water injection station. What else did we do? 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 are putting it, and keep our rates up in order to continue to increase our production or at least maintain production. That is part of what we did to stabilize the production. In addition, we purchased a hot oil unit. We use that every day. Dante alluded, mainly that's to flush out flow lines, do pressure tests on flow lines, etc., and so on. That reduced our LOE about $30,000 per month over third-party use of a hot oil unit. I'll talk a little bit more about that as I discuss the LOE. We 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. 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. We're hopeful that as we come into 2025, we're going to be around $700,000 per month on our lease operating expense. We anticipate even reducing that further. Next slide, please. 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. We moved on to pumping low-temperature resin-coated sand. 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. We had to do something different to eliminate that sand. It was causing excessive well pools as a result. The last several jobs we've done, we've pumped low-temperature resin-coated sand, and they've been successful. The first one has come in at 20 barrels all the day. That's what we expect on a go-forward basis as an average. We also are bringing idle wells back on production that have some type of down hole 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. We've started returning those wells to production. That, again, helps stabilize and increase production a little bit. In addition, as we've stated, our water floods and the injection wells are very important. We found that there were injection wells that were down for various reasons. We've returned some of those back to injection. That is an ongoing program. Finally, what's been really a highlight is 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. We're actively seeking a partner to come in and help with the cost. The plan currently is we're in the process of permitting those 12 wells. 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. 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. Yeah, thank you. Thank you, Jesse. Thank you, Mitch. Guys, to wrap up our presentation here, we think we're going to hit some home run balls in 2025. 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. That works out to be a little more than $2 a share. We're going to get that done mid-year. 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. 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. I believe we'll do at least one more. 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. That's it. That's kind of a five-home run inning. 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. Certainly. Everyone at this time will be conducting a question-and-answer session. If you have any questions or comments, please press star one on your phone at this time. We do ask that while posing your question, please pick up your handset if you're listening on speakerphone to provide optimum sound quality. We do ask that participants please ask one question and one follow-up, then re-enter the queue. Once again, if you have any questions or comments, please press star one on your phone. Please hold while we pull for questions. Thank you. Once again, everyone, if you have any questions or comments, please press star, then one on your phone. Please hold while we pull for questions. Thank you. That concludes our verbal Q&A. For those of you listening on webcast, you can submit a question at this time by clicking on the ask question button on the left of your screen. Type your question into the box and hit the send button to submit your question. I'll now turn the call over to Michael Porter for remaining questions. Thank you, Matt. Gentlemen, the first question that comes up, it says, "Congratulations on your progress. What are your largest concerns that might negatively impact your plans?" Also, "What are your plans regarding future use of stock in lieu of cash for AP and other liabilities?" The follow-up question is, "How is the stock valued and is it fully registered when issued?" Gentlemen, would you please answer the questions? Let me start that one, and then I'll turn a little bit over to Dante. First, our largest concern is, of course, the market. Everybody's got that. Oil prices go up and down, stock prices, the market tariffs, and all that. Everybody from Exxon and Apple down to companies like us, nobody knows what's going on. Let me address the stock questions, and then I'll give 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? The $500,000 I already talked about. Over half of that was settling debts that related to acquisition. 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. We will use it sparingly. 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's the stock valued? That's actually two different questions. One is, what is the valuation from a GAAP standpoint? That's just the base. That's a gap thing based on the date of the grant and the stock price. How do we value it with respect to the issue price is the bigger question, I believe, in here. 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'll fluctuate. 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. These shares are not registered. They are unregistered shares. They get issued. The next S-1 will allow us to register them. You can look in the past at all the registered shares in our S-1 filing. That's basically what it is with that. Dante, did you want to hit on any of your larger concerns? Yeah, I'll put one out there. I mean, we have a low lifting cost to $23 a barrel. 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. It also makes me want to look at gas. Gas is behaving better in the market than oil. We may look at that, look at gas in the coming years, at what we can do as a hedge against a weak oil price. 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. 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. I think we've got time to react and to study and to understand what the markets are going to give us. That's my response. 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? I might try to answer that. The workovers are tied in with the Seven Rivers. Some of the workovers are to add patterns. 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. 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 developed 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. 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 acid or frac, we just have no end of fun there. Now, I'll go to Jesse. Did I say that about right? Yes, sir. Yeah, most of our workovers will be in the Seven Rivers, plugging back and then adding Seven Rivers perforations, both in producers and injection wells. As you've mentioned, the vertical workovers that we have are to test intervals within the San Andres. Our geophysicist 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 a local interval name within the San Andres section. Yes, we save 50 horizontal wells currently. That could double or triple with the identification of these additional benches that we could go horizontal. The future looks very, very bright for us from a workover and/or drilling horizontal completion standpoint. 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? Dante, I think I can take that one there. Yeah, please. Go ahead. Obviously, the Permian Basin and even where we're at in the Northwest Shelf there in New Mexico, prices are quite competitive. 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. 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. We are 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. Thank you. That probably answers your question. Yeah. Go ahead. Next question. If we get a nice recovery with WTI oil at $85-$90 a barrel this summer, would you try to increase production faster, reworking horizontal wells, etc.? Yeah, I'll answer that. Yeah, we would. We are limited by the funds we can raise. As the oil prices go up, our access to funds greatly increases, as does our access to funds with the stock price. 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 acid stimulations. Frankly, last year, we went too fast and made some mistakes and then just slowed it down. The answer is yes, we'll accelerate, but not to a ludicrous speed. 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. The horizontal wells, they're all incremental. I will look at it, and 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-$90 range a year ago, and we locked it in all the way through the end of 2025 thanks to that. If something like that pops up, we're going to take advantage either for later parts of 2025 or going into 2026. We watch it to make certain our hedging program is proper. Now back to you, Mike. Okay. Last question. Regarding the $52.8 million revenue-sharing volumetric funding arrangement with OnStream Capital, is this funding deal still on track for June 2025 closing? Thank you. Dante, you want to take that one? Yeah, I'll answer it. So far, the lender is saying yes. Until it closes, frankly, I'm nervous. 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. We've got backups in place to cover the shortage. We've got a backup A and a backup B and a backup C. It would sure be helpful for us to have oil prices stabilized in the $65 range or better as we head into June. 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 timeline? I'll answer that. It really ties into the OnStream. Part of that program has the $52 million, $53 million, as just under $10 million for those 50 wells. That is already prearranged, and it will close at the same time. If things, for some reason, work out, maybe we can do it sooner. Yeah. Then we will kick off the program of actually doing the work, which will take a few months. Okay? Okay. One more question. With President Trump saying, "Drill, baby, drill," are you seeing new drilling permits going through faster for your going forward? What is your relationship with drilling permits with the state of New Mexico? I will let Jesse answer that. Yes. As most people probably know, the regulatory environment in New Mexico is a little tougher than Texas. As Dante has already said, we deal with it. The drilling permit process is typically an eight or nine-month process. With the new administration, all indications are maybe that's going to be a five or six-month process. To answer that question, yeah, it does look like the environment has improved for permitting. The same goes for the workovers. Because our property is BLM land, Bureau of Land Management, federal land, and state land, we have to get approval typically from both agencies. Workovers do take longer than they do in Texas, typically two to three months. We are fighting a little bit at that now, but we're working on relationships. Hopefully, by the time we're funded with OnStream, those permits will be approved, the workover permits. To conclude, yes, the environment is improving, and it is probably a result of the new administration having come into office. Thank you. Dante, that's the last comment, last question. I'm turning the meeting back over to you. Yeah. I just want to say thank you to all our shareholders. We're grateful for all of you. We know you've put your trust in us every time you buy a share. 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. We've got a lot of knobs to turn, as we mentioned today, to keep us on track to a very profitable 2026. We think in the trailing quarters of this year, you're going to see remarkable results from us. With that, I'll turn it back over to Matt to wrap it up. Thank you. Everyone, this concludes today's event. You may disconnect at this time and have a wonderful day. Thank you for your participation.