Greetings, and welcome to the Ring Energy 2020 First Quarter Financial and Operating Highlights. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. Please note that this conference is being recorded. At this time, I'll turn the conference over to Mr. Tim Rochford, Chairman of the Board of Directors of Ring Energy. Mr. Rochford you may begin.

Thank you, operator, and welcome all listeners to our 2020 First Quarter Financial and Operations Conference Call. Again, I'm Tim Rochford, Chairman of the Board. Joining me on the call this morning is our CEO, Kelly Hoffman; our President, David Fowler; Brandy Brodrick, our CFO; Danny Wilson, Executive VP and Head of Operations; Hollie Lamb, VP of Engineering; and also Bill Parsons, our Investor Relations. Today, we're going to provide a quick, concise overview of the financial and operational results for the first quarter. And as we did on our year-end 2019 conference call, we'll spend the majority of the call identifying, discussing and summarizing the factors that directly affect the current and future operations of your company. At the conclusion of the first quarter review, we'll turn it back over to the operator for opening up questions to the listeners. Now at this time, I'm going to ask Randy Broaddrick, our CFO to give us a brief overview of the activity financially in the first quarter. Randy?

Thank you, Tim. Before we begin, I would like to make reference that any forward-looking statements, which may be made during this call are within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. For a complete explanation, I would refer you to our press release issued Monday, May 11. If you do not have a copy of the release, one will be posted on the company website at www.ringenergy.com. For the three months ended March 31, 2020, we had revenues of $39.6 million, net income of $43.8 million and earnings per diluted share of $0.64. This net income included a pre-tax unrealized gain on hedges of $47.1 million. Without this unrealized gain after the effect of income taxes, our net income would have been $7.2 million or $0.11 per share. This unrealized gain is recorded, because the value of the derivatives changed as a result of the changes in oil prices. During the quarter, we had $23.9 million in net cash flow and $16 million in capital expenditures. For post-CapEx positive cash flow of approximately $7.9 million. For the three months ended, we had sales of 855,603 barrels gas sales of 795,551 Mcf for a total of 983,195 BOE. Our received prices were $45.16 per barrel of oil, $1.22 per Mcf of gas for an average BOE price of $40.25. On prior conference calls, we have made comparisons of our current results with the prior year's results for the same time period. We have refrained from doing that this time in order to spend more time on current events. Those comparisons are in the news release put out yesterday. Before I turn it back to Tim, I'd like to highlight a few key points that I believe are major factors in our ability to operate in the current environment. For the first quarter 2020, we had a pre-tax realized gain on hedges of $3.3 million. That's realized versus unrealized before. This amount was received in April for March hedges. The hedges we have in place are financial instruments and we will be paid based on the hedges we have in place versus the index price, regardless of any actual production or sales. We do not have to have matching production to receive payment on the hedges. The spring redetermination on our credit facility is in process. We have provided the bank group with the normal information we generally provide, including updated reserve information. We are currently in compliance with all covenants of the credit facility. The redetermination should be completed within the next few weeks. We have an opportunity with some of our vendors to receive discounts on outstanding invoices in return for paying those invoices up to current, as such we drew $21.5 million on our credit facility in order to make those payments and in return we have saved over $2 million. As most of you are aware, we filed an S-3 recently. This was a shelf registration. This was done because the shelf registration we had in place previously had expired. Ring has always kept a shelf registration active as we believe it is prudent to have that availability if needed. The company does not have immediate plans for use of this shelf registration. With that, I'll turn it back to Tim.

All right. Randy, thank you. I'm going to ask Kelly, our CEO, to give us a brief overview of the activity over the first quarter.

Thanks, Tim. As Tim mentioned in his opening comments, we feel it's very important to minimize the time spent on the call reviewing our first quarter, and you've already heard, but there's a release describing in detail the financial and operational results for the first quarter that was put out yesterday. And as Randy mentioned earlier, if you have not seen, a copy of that’s available on our website at ringenergy.com. We've been experiencing now – really everyone has been experiencing; every operator is experiencing right now an unstable, unpredictable pricing and storage dilemma. And because of the lack of storage capacity, there's a large differential between WTI spot pricing and the actual price a buyer is willing to pay or the wellhead price. Until the markets improve and we begin to see the world economics at work again, we have to be prepared for this continued uncertainty. And before I turn it over to Hollie and Danny to give you a little more color on several of these items, there are a couple of things I want to point out. First of all, let me address the Delaware sale, which as many of you know we previously announced that we had entered into a PSA in April and the buyer has now started required due diligence. We're continuing forward with answering questions and field business and things of all that nature as they come up. Closing is still estimated to be in June and we plan to use the proceeds to reduce our outstanding debt once we close the transaction. Also worth mentioning is that we continue to cut costs. You heard Randy mention the reduction in invoices and things of that nature. But we've gone over and above that. Besides us already being a very low-cost operational company in general, we've continued to reduce G&A, we've continued to reduce LOE and especially our CapEx across the company and we'll continue to cut those costs as we are able and as needed going forward. And with that, I'd like to ask Danny, our Executive Vice President of Operations, and Hollie, our VP of Engineering, to walk you through the steps that we're currently taking that we believe are necessary to ensure our ability to not only weather this storm but to come out a stronger company in the end. Danny?

All right. Thank you, Kelly. I appreciate it. Let me start out with just a real quick recap of our first quarter operations. For the quarter, we spent, as Randy mentioned, about $16 million in CapEx. During that time, we drilled four wells and performed nine rod conversions. The drilling consisted of two one-mile and two 1.5-mile wells on the Northwest shelf. The average IP on these new wells was over 600 BOE per day. And although our total production for the quarter was down slightly from Q4, we were able to finish with a higher exit rate of 11,474 net BOE per day in March versus 11,270 BOE in December, and this is with only drilling four wells in the quarter. A little bit of lumpiness there is just caused by timing, nothing else. Using our new frac procedure and our refined drilling and completion techniques we started using at the beginning of the fourth quarter, our new wells continue to exceed our type curve and our expectations. In a few minutes I'm going to address our current operations and our future plans. But for now I'm going to turn it over to our Vice President of Reservoir Engineering, Hollie Lamb, to address a few issues.

Hi. This is Hollie Lamb. I am touching base on an article that was published late last week and reinforcing how we look at our reserves. The article made the first assumption that all San Andres wells are the same everywhere in the Permian Basin. There's a great variation in San Andres depositional environments across the Permian Basin and amongst the individual basins and platforms that are subgroups within the Permian Basin. These different environments result in different rocks with different reservoir characterizations, such as pay thickness, permeability, and porosity to name a few. Our lateral lengths of our wells that we have completed to date vary from 1,929 feet to 7,088 feet. Our type curve is 5,080, which is an effective one-mile lateral. We derive our San Andres horizontals from two independent geologic areas with different depositional environments having very different pay thicknesses that range from 500 feet to 100 feet. They contain multiple spacing options, multiple benches, and we have completed them with various techniques. How do you make the assumption that all wells are equal? Only 6% of our wells IP on the first day of the month based on what we've done thus far. Using public data, one would only observe the highest recorded month, which means 94% of the time a 30-day IP drive from public sources would be wrong. Therefore, their assumptions are correct 6% of the time. Assuming their math is correct 6% of the time, we can then focus on type curves, which are not solely a function of historical data; they also include what geological region they reside in, the pay thickness, landing zone, how we evaluate the landing zone, percentage of lateral in zone, the length of completion, type of completion and how we bring on our initial production. As far as their assumptions on the reserve report, there are many assumptions that go into our reserve report except where we have the data, so that the assumptions are very calculated. They include LOE differentials, working interest, net revenue interest, non-operated properties, PUD timing, PDNP cases, recompletion opportunities and many others. Our reserves are independently reviewed by a third-party engineering company that is very well-known, Cawley, Gillespie and Associates began serving the oil and gas industry over 50 years ago and has continued uninterrupted business throughout the decades and today delivers professional, ethical, reliable engineering and geological services for the petroleum industry. They have major clients such as Concho, GE Financial, Wells Fargo, UBS, Morgan Stanley, and ConocoPhillips, but they have hundreds of both public and private clients. Our reserves are also reviewed twice a year by our syndicated bank groups, which all have in-house engineering departments. All data that is entered into our database is independently examined by internal and external auditors. As Danny mentioned, as of the six wells we IPed in 2020, all of them were Northwest Shelf wells and they had a range of IP of 438 BOE to as high as 813 BOE per day with an average of 558 BOE per day. The four wells that we completed in Q1 2020 had an average IP over 600 BOE per day. Our type curve is 400 BOE per day. This year we have exceeded our type curve on every single well that we have drilled. We have stated on various occasions that our IPs are statistical and that there are going to be better and worse areas. But what I think our 2020 drilling has demonstrated is that we've hit the sweet spot in the Northwest Shelf and we're excited about getting back to drilling when the market is ready. Danny, with that I'll hand it back to you.

All right. Thank you, Hollie. I want to add just a few points of emphasis on what Hollie has to say. First, it's extremely difficult to adequately perform a reserve evaluation based on publicly available information only. There's just too many assumptions that have to be made. Every year we have a small army of professionals, whether it's third-party engineers, engineers at our banking syndicates, the bankers themselves, independent and third-party auditors, and our internal auditors that review our information every year, twice a year. These people have full access to our production, reservoir, geological, land, and financial information and they've reaffirmed our reserves twice per year every year since we have been in business. And the third point I'd like to make is, much like someone who claims that something isn't about the money, we always know it's about the money. It has been my experience that when somebody claims that they don't have an agenda as is the case with this recent article, we always know that there is an agenda. And with that, I'll move on to our current and future operations. Beginning in mid-April at the request of our purchaser Phillips 66, we began curtailing production on the Northwest shale from a little over 7,000 barrels a day down to 6,000 barrels a day. They, like every other purchaser, were concerned at the time about having adequate storage but also wanted to keep enough oil flowing to meet their needs at their Borger refinery. Based on the crash in oil prices we saw at the end of April, we proactively took further steps to lower production outside of the Delaware to near zero by the 26th of the month. Starting about a week ago, we began turning on some of the wells at a reduced rate with the goal of producing enough oil to sell production on every well in the CBP and Northwest Shelf during the month of May. Currently, we are producing at about 15% to 20% of normal production capacity exclusive of the Delaware. We are accomplishing this by turning on a few wells at a time, letting them produce long enough to sell production, and then shutting them in and turning on another set of wells. In April when we started shutting down the wells, we went through a process of pickling the wells with chemicals, which include corrosion inhibitor, paraffin control, and scale inhibitor. This was done in an effort to ensure that we have the least amount of trouble when we restart the wells. This process will be followed again each time the well is shut in until prices recover enough to bring the wells back on full-time. As we're holding the leases under our existing wells, we feel that we are being proactive in satisfying our lease obligations with our current strategy by showing significant production from each well each month and then selling the oil when it makes sense. On our undrilled acreage, we are exercising options where we can in negotiating with the mineral owners for extensions on the remaining acreage. And so far this has been working out quite well. When the time comes to bring production back to full speed, we feel this can be accomplished over a 10-day to a two-week period. Our rod pump wells can be turned on at full capacity with no problems. But the ESPs must be restarted slowly and then sped up over a number of days until they can reach full capacity again. As for our pricing required to bring production back on, just like everybody else, we're monitoring prices and differentials daily. We believe it makes the most sense to turn the wells back on to full-time production once we see sustained pricing in the low to mid-$20 per barrel range, and that's at the wellhead, inclusive of all differentials and transportation cost. And I just want to remind everybody that's not a one-day event that is an average across a month. We get paid on a monthly average. So we say that we need to see sustained pricing near $20, because we don't want to get caught in the W Shape type pricing scenario where once prices get back to a point everybody feels comfortable turning their wells back on, that everything comes back on to full production not just us, but everybody else. And all of a sudden, we're back into a storage capacity issue again. So we want to see that pricing sustained over a period of time before we're willing to bring our wells back on full-time. Our purchasers are anxious for us to come back online as soon as possible. I have daily in constant communication with our buyers. The purchasers are being very creative with the ideas to give us some guarantee of profitability. We've had several discussions with purchasers that ask what price do we need to be at and they're looking at the possibility if we can reach that point at some time during the month, they will go out and secure pricing that will allow us to have stable prices for a period of time whether it's a month or two months whatever the price, whatever the case may be, but in all cases, they're extremely anxious for us to get back to production. As for drilling, we feel like our prices need to be sustained in the mid-30 range, again, inclusive of all differentials in transportation costs. At this level, our economics, particularly in the Northwest Shelf become attractive with our internal rate of returns in the 70-plus range in our discounted ROIs of approximately 2.5:1. As Randy mentioned and it's in the press release, we have amended our CapEx for the year. As you've seen, we've reduced it to $25 million to $27 million. With roughly $16 million of that being spent in the first quarter. The range of spending is to account for the unknown timing of returning wells to full production and doesn't account for any drilling for the remainder of the year. This lower budget emphasizes our focus on maintaining free cash flow while still being able to perform the critical tasks needed to maintain the integrity of our operations. Even though we are producing at a significantly lower rate, there is still work to be done. We plan to continue our program of converting wells from ESPs to rod pumps as needed. Typically this will be done when a well fails. And we will also continue rightsizing our ESPs when it's appropriate. We're seeing tremendous progress in lowering our equipment failure rates as we go through this process and thereby lowering our LOE and future capital needs. And with that I'm going to turn it over to our President, David Fowler.

Thank you, Danny. Over the past several weeks I've had a number of conversations with middle operators representing both independent and private equity-backed management teams to just gauge what percentage of their production volume is shut in or curtailed. Two private equity-backed management teams I spoke with both had exceptional hedge books and really only had minimal production cuts. One had a shut in of approximately 20% and the other one was about 5%. Now the majority of the independent producers I spoke with reported shutting 100% of their production. All remarks as selling a barrel of oil for a single-digit oil price which is simply giving it away. And most of those were unhedged, of course. The independents that were still producing, but on a limited basis had a few leases with extraordinarily low lifting costs and were able to continue to pump those wells profitably. There may be some exceptions, but the independents who shut in all of their production did so voluntarily due to oil price and weren't necessarily curtailed by their purchasers. An interesting insight from an operator that I hold in high regard shared that the rapid pace of shut-ins across the Permian Basin and other basins have been so significant that it has caught some oil purchasers long on their nominations and that they're now coming up short on barrels. As a result they're reaching back to producers with a stronger wellhead oil price to get more barrels to flow their way. Based upon my limited conversations, it seems to indicate that the magnitude of the shut-ins and curtailments by independent operators across the U.S. could be substantial and may mirror the 1 million to 1.5 million barrels reported by public companies to date. If oil prices at the wellhead stay up $20 a barrel, shut-ins will probably continue through May and June, and it may prove out that the 2.5 million to 3 million barrels a day that has in fact been shut in or curtailed across the U.S. could have a positive impact on the speed in which the market rebalances; of course time will tell. On the M&A landscape, we anticipate deal flow to be robust between now and year-end as companies seek to consolidate with peers that have leasehold positions in similar geologic plays. The motivation or purpose is to create a stronger, better financially positioned E&P, so when the energy supply-demand picture improves they'll be far better off. But we stay attentive to what's going on in the market in our core areas; our primary focus remains staying on strong financial footing so that we can successfully navigate the volatility in today's market. And Tim, I'll turn it back to you.

All right, David, thank you. I'm just going to make a couple of comments before we turn it over to the operator. I think it's important to point out that as Co-founder of Ring Energy and Chairman of the Board, I personally want to thank all of our management team, all the support personnel for the tremendous job that's been done in this very unparalleled time. I've been in this business 40-plus years and I've been through a number of cycles both good and bad. This management team has worked around the clock, examining every aspect of operations, all for one reason: to posture Ring Energy not only to survive, but to excel. We will focus — going forward we will focus our attention on the two excellent assets at hand; Northwest Shelf and Central Basin platform. Both of these assets have years of drilling and development opportunity. I am confident in our ability to become one of the post-virus, post-war or price war success stories. So with that, I'll turn it over to Rob, our operator. And Rob you go ahead and open it up for questions that we might have for our listeners.

Thank you. Our first question is from the line of Neal Dingmann with SunTrust Robinson. Please proceed with your question.

Great. Nice details. Kelly, my first question is about your financials. I want to clarify something I think I heard correctly. Do you believe that your total overhead can be covered by the financial hedges for this year? Can you provide some insight on that and possibly how it ties into your survival plans amid lower prices? Also, could you discuss the costs associated with these hedges?

Sure Neal. Look good question. Let me just answer that quickly and then hand it over to Randy and help give a little more color on it. The short answer to that is, yes. Yes, our hedges will cover our overhead going forward. But Randy, you want to add a little more color onto that?

Sure. Yes. At sub $30 prices the hedging does allow — provide enough cash flow to cover our overhead, G&A, interest expense, so forth. Obviously, as discussed at $30 prices unless the differential is out of line it would bring production back on. But, and then at lower WTI prices, the hedges actually would generate even more income. So as Kelly said the short answer is yes, the hedges would provide enough cash flow to cover our overhead.

Very good. And just one follow-up on the ops, if I could maybe turn it over to Danny. Just it's been over a year now, since you guys have been accurate on the shelf, I'm just wondering how do you think about the latest curves in that play now? Versus I'm looking I think it's slide 11 if I recall in today's slide your prior curves. And maybe if you could just give some thoughts on again I know you don't have new curves out but just Danny any color you could give around that.

Yes, I appreciate that, Neal. The curve shown on slide 11, which is our type curve for the Northwest Shelf, was developed during the initial Wishbone acquisition based on our analysis of the wells they had drilled and served as a forward-looking model. We recognized that it was quite conservative. After discussions with other operators in the region, particularly our colleagues at Stewart Energy, we established a different frac approach compared to what we've implemented on the Central Basin platform. We also introduced various techniques for well completions and opted to bring them online at slower rates to prevent issues like scale, which affected earlier operators in the Northwest Shelf. As a result, we've observed outstanding outcomes in that area. We've considered when it might be appropriate to revise this curve, as I mentioned earlier; we only began this new approach at the beginning of the fourth quarter. While we are aware of its success and that we're surpassing the type curves, we prefer to gather a bit more historical data before making any updates. Furthermore, this curve also reflects our expectations for challenges we might face as we explore less drilled regions. It's a matter of finding the right balance. We have valuable wells and believe our research indicates promising areas outside the ones that have been the focus thus far. However, we want to hold off on revising the curve for now, even though we anticipate easily exceeding it over time.

Perfect. Thank you.

Our next question comes from the line of John White with Roth Capital. Please proceed.

Good morning. Thanks for all the detail. Danny touched on this. I was wondering if you get a little bit more explanation you differentiated between rod pumps and ESPs with the wells on rod pump being very easy to restart and ESPs needing to move a little slower. Can you give us some more detail on ESPs?

You bet, John. That's a great question. It does take longer to ramp up than some might expect; you can't just turn a switch and have everything return to normal right away. The rod pumps are straightforward to start and can quickly return to full production capacity. We've seen this recently when we turned on our wells and began with the rod pumps, resulting in a production increase that exceeded our expectations. However, the ESPs are different since they are located downhole. To operate them, we adjust the pump speed by changing the electric current in hertz. For example, if we start a well, the manufacturer might recommend a starting speed of around 55 hertz. We monitor the fluid level over time, and assuming it's stable, we can gradually increase the speed by one or two hertz at a time. This gradual ramp-up is crucial because we want to avoid running the pump at full speed too quickly, which could disrupt fluid movement and allow gas interference, ultimately damaging the pumps. ESPs prefer consistent operation at a steady speed rather than being turned on and off. Our procedure ensures a slow start, and part of this includes pickling the wells during shutdown. We load them with corrosion inhibitors, paraffin inhibitors, and scale inhibitors to prevent issues while they are offline.

Junk.

And that's when you have problems is, if you have a lot of, let's say, sand or scale or something, even iron that will come down, over time it settles out of the fluid and then it will come and sit down on top of those pumps. And then when you try to restart them, you have that junk in the hole and that can twist a shaft very quickly. And so, you just have to be a little bit more careful with it, but I think starting at the slow rate, pickling the wells ahead of time, will eliminate the vast majority of those issues.

Our next question comes from the line of Richard Tullis with Capital One. Please proceed with your question.

Thank you. Good morning, everyone. Maybe a question for Danny. If you could, recap again the shut-ins for April and what you expect for May between curtailments and shut-ins, Danny, please?

Yes, you bet. Now, as I mentioned, when we went into April at our highest rate that we had for coming out of Q1, at almost 11,500 net BOE a day. Phillips called probably maybe towards the end of the first week of April. And as I mentioned, they were like everybody else, we were seeing all these reports about storage filling up and everybody was getting very concerned and they asked us if we would slow down a little bit on the Northwest Shelf. We discussed that internally and we decided, since Phillips is a very important purchaser for us. And let me just throw this out there, in the meantime not only are they the purchaser on the Northwest Shelf, but now they are a purchaser on the Central Basin platform. They asked us to slow that down, which we did, and they were very grateful for that. And then, when we had the day there around the 20 or so of the month and that price went minus $35 and we saw what that was going to do to the average pricing for April, we had a lot of discussions internally and we decided our best move at that time was to go ahead and just shut production down. And we did that across the Northwest Shelf and the Central Basin platform. We did leave the Delaware running, because we were in the middle of the work we're doing with due diligence and with the new potential purchaser in the Delaware. So, we did leave that going, but we did shut down the rest of the production. Moving into May, our goal was to show enough production on each well that we could show significant production on those wells. We also at the end of April sold everything we could sell, left our storage as empty as we could. And so we have a lot of internal storage right now in our system. So what we did, we're bringing wells back on beginning about a week ago, producing them for three to four or five days and then shutting them back down, putting that well — putting that oil in storage, and then we're restarting the other wells in the area. So I think we at least anticipate through May that we will see — this will be the procedure. So, we're producing at about 10% to 15% of capacity in the Central Basin platform on the Northwest Shelf. We'll see where the pricing for June, what it looks like, and we'll see the big thing the pricing is not even as important as the differentials. When you get the WTI, WTS differential you get the CMA role. You get all those components that go into the pricing, those all settle around the 25th of the month. And so we'll have the price set for June at least futures prices for June will be set around the 20th, the differentials will be set around the 25th. And so at that point, I think we'll have a better idea of what June looks like. I will say just to give you an example of where we're at today. Today's price, when I looked earlier was around $26, but the differentials for May are about $12 for us. So that only puts us at about a $14 price, which isn't enough for us to bring everything back on. We are seeing the differential shrink in June and then even moving further out, we're seeing them getting even lesser as we're moving out. So, I don't know when we'll get back to full production, but it is getting better.

In our average differential over before this turbulent time had been about $2. So the $12 that Danny just quoted was by far the most what we've seen in the differential since kind of late 2018s.

Richard, this is Kelly. I want to make a comment in addition to what Danny was saying just for clarification. Where Danny was talking about Phillips asking for curtailment early on and that was important and we cooperated with that in an effort to help and sustain that relationship there. As time has gone on though, the storage is not the issue for us at this point in time. So, we're voluntarily doing this as a result of price. That's more important to us right now, whereas, if we wanted to ramp up today, storage is available for us. We could increase our capacity. Would you agree with that Danny?

Yes. Yes. In fact Phillips, like I say, I have constant communication with them and they would love for us to come back up to a higher production level.

That's very helpful. Thanks to all of you. And just lastly, for me, you saw a substantial reduction in cash G&A quarter-over-quarter in the first quarter. Randy is that – or Kelly is that a pretty good run rate going forward? Should we kind of look for similar type numbers as we move forward?

Yeah. I think what you saw in the first quarter is a good run rate for what we'll see for the rest of the year.

Our next question is from the line of Noel Parks with Coker & Palmer. Please proceed with your question.

Hey, good morning.

Good morning, Noel.

All right. Just a few questions. We kind of touched on my first one a second ago. So modeling out for the rest of the year does it seem like sort of that a $12 differential range is about as bad as we should assume it gets? Or do you think worst-case could even be a little uglier?

That's a great question. Danny, I know we've spent a lot of time crunching those numbers. What's your sense of that Danny?

There's a lot of things that go into that. Let me start out by saying that. And a lot of that is getting the economy restarted. But once that thing, once it gets going. But the market is usually pretty smart about a lot of this stuff. And what we're seeing as we look out into the future — and I don't have those tables in front of me right now, but I think April was our low point. I do think that was the case and I think we'll see things improving through now through the end of the year.

So, Danny just to be clear for Noel and the other listeners so by the 25th of this month we'll know what that differential is going to be fixed at for June's production correct?

That's correct.

Okay, great. And about the rod pump conversion and I'm sorry if you touched on this earlier and I just missed it. Where do you stand relative to your overall inventory of those conversions, but roughly what share of those that you plan to do are already done and how many still lie ahead?

Yes. So, we've probably done about a quarter now of our wells. And again, it's a matter of when the wells reach the fluid production when that production drops down to a point where it makes sense. And again we — what we typically do is we'll wait for the ESP to fail and then we'll come in and do the rod conversion. We have really and I said this and at some point, we may even put some slides in the presentation about this we've lowered our failure rate from over what we call it one-time per year per well, so going back and historically, before we started doing the rod conversions a well would typically fail somewhere around six to nine months on a consistent basis. And what we've done now is we've lowered that down to a point where on average we're averaging a little over — almost two years between failures. Now, there's a lot that goes into that. But that's just an example of what we've been able to do by following this program. And again it also goes back so that's lower — that lowers the failure rate means we're pulling fewer wells. But it also we're lowering tremendously lowering future pulling costs. Typically, we'll spend $150,000 to $170,000 pulling an ESP and replacing it versus about — we've been averaging about $30,000 a job on the rod when they go down. So, a tremendous savings for us in the future LOE and we see the same kind of response even by when we start out with very large ESPs and in these wells because we're moving a lot of fluid initially. And then over a period of time as the fluid level comes down, if that larger pump fails, but it's not quite ready to put on rod pump, we’ll run in a smaller ESP that's much more efficient at those levels. And that all this plays in to the best — I mean it's a tremendous improvement in our failure rates.

Great. Thanks. I just wanted to double check the times presented in the slide deck that show the internal rate of return at different price scenarios for both the shelf and the recent platform. I can't recall if those numbers are based on your original type curves or if they have been adjusted based on what you've observed in the field.

So, we've had gone through several iterations on the type curve on the CBP and one iteration on the Northwest Shelf. And the type curves that you're seeing in the corporate presentation as Danny previously discussed, the rod conversions are very accretive. They make us a lot of money. We spend a little bit but in the long run it's much better for us. So, both cases contemplate a rod conversion at 365 days from peak production rates and we kind of got to that number by looking historically across both basins and projecting where we're getting to that sweet spot of fluid level or fluid movement that we can convert from that larger volume ESP to the smaller volume rod.

Okay, great. And just my last one. I was listening to another smaller company with a single basin focus that also has done good hedge coverage and they happened to remark last week that they have been getting more inbound calls from folks looking to offer financing. I'm just recurring to various terms. Then they can ever recall happening in this current environment. So I was just curious what you're hearing is as far as just folks who would like to find a way to give you money.

That's a good question. Yes, that is definitely a good question, Noel. And comparing to the other company I would say that absolutely we have probably seen more density in inquiries and over a two-month period than we – in the other two-month period prior to that. Not only for the inquiry as it relates to possible financings available in different sorts not just your traditional conventional banking but outside of that. In addition to that there's been a number of inquiries as it relates to folks that are interested in doing something along the lines of participating somehow or some way with the company, whether that's to join in as a side-by-side idea or whether it's to join in as a joint venture. There's a lot of a variety of ideas that have been kicking around more so than what we've ever seen before.

Thanks a lot.

Thank you, Noel.

Thank you. Our next question comes from the line of Dun McIntosh with Johnson Rice.

Good morning. Regards this year's budget, you all were out pretty early drops in all D&C activity in early April and took your CapEx budget down to $32 million. Last night it sounds like you all shaped another $5 million or so off of that. What's the driver there? Are you still going to – obviously, you're still focused on the pump conversions as you've been discussing. But maybe a few less of those than you were thinking about or more favorable service terms? Any color there would be appreciated.

Yes. No Dun. What we've done is we've gone back and studied what we can see historically is our failure rate and we've cut back just to the bare minimum. So we're not proactively doing the rod conversions like we were last year and even in Q1 where once a well did reach the point where it made sense to put it on the rod conversion we went ahead and did the job. What we're looking at now is with the lower production rates, we think that the failure rates could be even a little bit lower. We're hoping. And — but even if they're not these are kind of just kind of a bare bones maintenance not even maintenance isn't the proper word. It's as a well that goes off and is a candidate for rod conversions. We'll go ahead and do it but we're not going to proactively go out and do those jobs. And so I think that's what you're seeing is when we first contemplated the $30 million to $32 million, we were going to continue doing nine to 10 rod conversions a quarter and now we're just going to do them on an as-needed basis based on our projections and that's the difference.

And I think, Danny's team has done an excellent job negotiating lower service costs in the down environment. And so I think part of that change in budget is seeing the new environment we're working in.

All right. Great. Thanks. And then sorry if I missed this but recognizing that the borrowing base redetermination is still ongoing. Any correlation there between the timing of that and the closing of the Delaware sale? And then do you — any other assets in the portfolio that you all could think about potentially monetizing not so much reserves but more along the line. I'm thinking more on the lines of midstream or SWD assets, particularly up on the shelf, where you've got a pretty robust portfolio there. Thanks.

Yes. Those are great questions. As mentioned earlier regarding Randy's comments, we are currently in the process of redetermination. We expect it will be another two or three weeks before we meet with the banking group. All the necessary information for this cycle has been sent over, and we are looking forward to that meeting and the results. The Delaware sale will help pay off about $30 million, which is just under 10% of the revolver, and while I wouldn't call it highly impactful, it will be significant. We are relying on that. Additionally, we feel quite comfortable about our compliance moving forward.

All right. Great. Thanks very much.

Our next question is from the line of John White with Roth Capital. Please proceed with your question. Mr. White your line is open for questions.

Hi, regarding the shut-in procedures and Mr. Fowler's comments on other companies' shut-in policies, I may have missed it, but could you clarify what the production was during April?

John we have not filed April production yet. So that's not publicly available but... We did curtail near the end of the month, but the rest of the month we were on track where we were in March.

You mentioned shutting in about 100% of starting April 23. So that's good.

Yes, John, it seems like a reasonable estimate would be to look at March and consider that the numbers might be off by a few days, possibly three, four, or five on average. That could get you close to what you're looking for. I haven't calculated it, but that would be my assumption.

As there are no additional questions at this time, I'll hand the floor back to management for closing remarks. Thank you, operator. We appreciate everyone's ongoing support and understand that you're busy, so we'll conclude the call. If you have any follow-up questions, feel free to reach out, and we will ensure that someone is available to respond. Thank you again for your time.

This concludes today's conference. You may disconnect your lines at this time. We thank you for your participation.