Greetings and welcome to today’s Ring Energy, Inc. 2020 Third Quarter Financial and Operating Highlights Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn this conference over to your host, Mr. Paul McKinney, Chief Executive Officer and Chairman of the Board of Directors of Ring Energy Inc. Please go ahead.

Thank you, Laura. And good morning, everyone. Thank you for taking the time to join us today and for your interest in Ring Energy. We plan to review with you our financial, operational results for the three and nine month period ending September 30, 2020, and to provide additional insight to our strategy and activities. Before we begin now, I would like to introduce the Ring employees that will be participating in the call today. Randy Broaddrick, our CFO will be reviewing the financials and Danny Wilson, our Executive Vice President and Chief Operating Officer will be reviewing with you the operations. Now before turning this over to Randy and Danny, I would like to make a few points about our third quarter. First, we had a very good one, our adjusted EBITDA increased almost 45% over the prior quarter and our free cash flow increased almost 46%. We reduced our bank debt by $15 million and exited the quarter with almost $18 million in cash on the balance sheet and a little over $32 million in liquidity. We were able to accomplish this by returning our well to production, significantly increasing our oil and gas production over the prior quarter, and by significantly reducing our LOE, G&A and capital spending. The gain we realize on our derivatives contributed as well. Looking beyond this quarter, we see challenges ahead. And I will be back to discuss some of these challenges and what we plan to do to meet these challenges once Randy and Danny review the details of our third quarter. So that being said, I will turn this over to Randy Broaddrick, our CFO to review the financial details of our third quarter results. Randy?

Thank you, Paul. 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 release issued Monday, November 9. If you do not have a copy of the release, one will be posted on the company website at ww\w.ringenergy.com. For the three months ended September 30, 2020, we had revenues of $31.5 million, net loss of $2 million and loss per diluted share of $0.03. This net loss included a pretax unrealized loss on hedges of $6.2 million, and approximately 600,000 and stock based compensation expense. Without these items, after the effect of income taxes, our net income would have been approximately $3.4 million or a gain of $0.05 per share. For the nine months ended September 30, 2020, we had revenues of $81.7 million, net loss of $93.2million and loss per diluted share of $1.37. This net loss included a pretax unrealized gain on hedges of $14.1, $147.9 million and ceiling test impairment and $2.6 million in stock based compensation expense. Without these items, after the effect of income taxes, our net income would have been approximately $14.2 million or a gain of $0.21 per share. The unrealized gain or loss on derivative – on hedges is recorded because the value of the derivatives changed as a result of the changes in oil price. The ceiling test impairment is the result of the reduction in the value of our reserves, as a result of a reduction in oil prices. During the three months ended September 30, 2020 we had $15.6 million in net cash flow and $4.3 million in capital expenditures, for…

All right. Thank you, Randy. As was mentioned in the operations update in October, our focus for the third quarter was on returning wells production after having been shut down for a significant amount of time in Q2. Our field personnel did an excellent job of bringing our fields back online, resulting in greater than 70% increase in production from Q2. Third quarter production increased to approximately 848,000 net BOE versus 495,000 in Q2 and third quarter daily production was up to 90,220 net BOE versus Q2 daily production of 5,440 net BOE. Due to the continued low commodity prices in Q3 we had no operated drilling activity. We did continue with our ESP to rod conversion program completing eight conversions during the quarter, six of these were Northwest shelf wells and two were on the Central Basin platform. Today we have converted 46% of our wells on the Central Basin platform and 58% on the Northwest shelf for a combined 51% across those areas. We continue to see a significant savings from the program, as future well work cost for the converted wells are reduced from 150 to $200,000 per job down to 20 to $40,000 per job, which depend on the work performed is a 70% to 90% reduction. In addition, we will see lower feature LOE cost from reduced electrical usage and the elimination of rental fees for the ESP. Evidence of this can be seen in our lower Q3 LOE of $10.11 cents per BOE, which is down from $14.03 per BOV in the same quarter one year ago. This is a 28% reduction. Another benefit of the conversion program is a greatly reduced oil [ph] failure rate. We've cut our failure rate measured in failures per month by over 0.5 from late 2018. This results in longer run times, which leads to greater production. This lower failure rate is a major factor in allowing us to maintain our production at higher than expected levels even with no drilling activity. In our second quarter call, we announced expected production levels for Q3 to be between 8900 and 9,000 BOE per day and instead we were able to come in at over 9200. And as for Q4, we expect production levels to once again be in the 8900 to 9000 BOE per day range. We continue to perform our workovers within budget and through the end of Q3 its been approximately $22 million on CapEx. At this time, we anticipate that we will finish the year within our announced CapEx budget of $25 million to $27 million. And with that, I'm going to turn it back over to Paul.

Thank you, Danny. And thank you, Randy. At this point in the call, I want to spend some time addressing some of our challenges. I believe you would agree with me that we just experienced a very solid quarter. We significantly increased our production by restoring the majority of our wells back online, made considerable progress reducing our cost structure. And our numbers reflect the benefit of all that. When compared to the second quarter, yes, we did well. But the challenges faced in this industry and the challenges facing this company are still with us. First, we find ourselves in this pandemic and due to economic downturn, that is keeping energy prices at historically low level. As we said in our release, we believe these conditions may continue longer than any of us would like. And so we are planning our business assuming prices remain pretty much as they are today. The second issue is our high debt level and relative size of our liquidity. Since joining Ring, I have been asked what we plan to do to pay down debt or perhaps a doubling [ph] what are the various alternatives the company is considering to pay down debt? To help answer those questions. First, let's discuss Ring’s strength. One advantage Ring enjoys is our low decline, long life conventional production base, characteristic of wells in the Central Basin platform in the Northwest shelf. We do not have high production declines that many of the shale producers experienced, forcing them to invest capital to maintain their production and cash flow. The capital we need to maintain our production levels are relatively low in comparison. Another benefit of our production base provides an inventory of what I call blocking and tackling type of investment opportunities, such as ESP to rod…

[Operator Instructions] Our first question comes to the line of Neal Dingmann with Truist Securities. You may proceed with your question.

Morning, all. Paul, thanks for the details. Paul, my first question would be, how do you think about when you and your team now evaluate the idea of bringing the rig back versus doing a deal? How do you - is it just simply return or you know, maybe give me kind of your mindset when you're thinking about those two things?

Yeah, it's a function of the merits of each of those investment opportunities. You know, when you drill a well, you get to production that you forecast from the well. But when you acquire assets, especially in today's environment, not only are you getting the daily barrels of production that come along with that asset, but you also bring along with it, a lot of the other things that are not truly getting valued in our current marketplace. And that would be the PDNP and the PUD, the PUD the undeveloped opportunities that may come along with that acreage. And so strategically, this is part of the reason why I've said, I prefer buying barrels in today's environment than drilling for them, because of all these other things that come along with it. We are a very effective operator in the areas that we operate. And so if presented with the opportunity to acquire more assets in that area, I think it just builds for a stronger Ring Energy in the future.

Great. And then could you just talk a little bit about, with that said, your thoughts about you've been able to hold production of, you know, even prior to you getting there and now since you've been there, can you talk maybe a little bit about baseline production and how you see, you know, the things you can do to hold that up or is just sort of the nature, sort of the assets, you think you'll be able to hold those?

Yeah. And this - your question directly applies to the comment that I made about our low decline long life producing acid [ph] The San Andres formation is characteristically defined with long life and shallow declines after the initial production. What I am seeing now in our production base, especially after we've returned all of our wells back to production, is just that, they're shallow declines. When you have a shower decline like that you have fewer barrels you have to replace, to have to grow. The capital required to maintain that production is inherently less because you have less barrels to have to replace. And so this is the strength, one of the big strengths of this organization. And we prefer, and want to always upgrade the portfolio of opportunities and properties that we have. And so we're always going to be looking for these types of opportunities. And Danny, I think you might have a point you want to make?

Yeah. Neal, and just to point out what are in the backup what Paul's saying, if you go back and look at Q1, where we drilled four wells in that quarter and brought those on, and we averaged production in that quarter about 10,899 net BOE a day and considering where we're at right now, we've only had a 15% drop off from that point over the year, which I think is pretty extraordinary, especially when you compare us to the different shale operators out there and the runoff they see in production.

Yeah, I would agree. Thanks, Danny. Thanks, Paul.

You bet.

Our next question comes from the line of Jeff Grampp with Northland Capital Markets. You may proceed with your question.

Morning, guys.

Good morning, Jeff.

I was wondering, maybe for you, Paul, or Danny, what do you guys think a new well might cost you guys today. And if you want to bifurcate it between the shelf and the platform, feel free to do so. But just I guess wondering, you know, you obviously haven't drilled the well in some time and seen some pretty meaningful cost reductions across the sector. So just kind of wondering if we look at your slides and the cost there, what a new well might cost relative to those numbers you quote>

Yeah. So Jeff, on that, so we're looking at about a $2.2 million on the Northwest shelf. And I think, honestly, I think we can get to $2 million or a little less on the Central Basin platform. We've been continually going through and evaluating this and talking to all of our vendors. And I think there's even a fair chance that we'll be able to lower those costs below that. But it just depends on the market, and when everybody else starts getting back to work. But - the vendors are very hungry right now. So I think we can easily do it in that $2 million to $2.2 million range.

Okay, thanks. And does that at all change? I think previously, you guys kind of said a $50 realized price net to you guys is kind of the inflection point. Before you also had some good discussion in the commentary about really liquidity being a focus and maybe new drilling make sense if it's liquidity accretive. Does - do some of those cost reductions maybe change that math internally for you guys? Should we still think about $50 realized is kind of being the go no go or any updated thoughts on that Paul?

Well, I would not at this point use $50 in go - no go type of decision. Because I can envision that we may be willing to pick up a drilling rig at lower prices, given the condition. Some of - in any drilling program, you have really, really good wells, and then you have other good well, or moderately good well. And so there's a range of outcomes on some of these locations. Some of our locations are in areas where we anticipate having superior economic to those that have been stated in our investor presentation. And so it will be a mix. I hate to link our go and no go decision to an absolute price. I think it has more to do with particular circumstances in the company, and where are we with respect to our liquidity and our needs going forward.

Okay, great. That's helpful. If I can just sneak in a clarification one, on the borrowing base front, can you guys clarify was the Delaware basin included in the current borrowing base or would retaining the asset come the fall redetermination kind of be additive to the collateral base?

The Delaware assets were included in the spring redetermination that occurred earlier this year. And so yes, and now those assets are going to remain in this - that same data set, whereas originally we were planning that it was not going to be.

Okay. Got it. Thanks for time, guys.

Thank you, Jeff.

Our next question comes from the line of Noel Parks with Coker & Palmer. You may proceed with your question.

Good morning.

Good morning, Noel.

I've had a few questions. And sorry I might have missed it earlier. But did you comment on rod pump replacement program, and I was curious if there was capital plan for that for the rest of fourth quarter and in the first quarter? And what roughly your inventory of remaining replacements ahead might be?

Yeah. Noel, this is Danny. Yes we do have additional work planned. The rod pump conversion is a little different than a lot of things in that. We typically wait for the ESP that's in the world of sale. We have - before we do the rod conversion, just so we can get the maximum runtime out of the ESP. But we now - we also have a pretty well known failure rate. And we kind of can’t predict what those are. And I think what you're seeing is, you know, I think six to eight per quarters, probably about a normal run rate for us on that. As far as the remaining inventory, so on the Northwest shale, we've already converted about 58% of the wells. So we're well along the way there of getting those wells converted over. And again, it's a timing as to when the well - the total fluid production of the well drops down to a point where it's feasible to put it on a rod pump. So they're going to occur at different times, on average, you can - it looks like we're probably going to hit those points at about the one year mark. And that's how we built our economics in the presentation, the investor presentation. As you'll see, we've got a rod conversion planned at the one year mark. And that's pretty accurate. On the Central Basin platform, we've done 46% of the wells. So overall, we've done 51%. Now some of these wells, and I must say maybe 10% to 15% of the wells will probably never reach a point because they're not maybe a higher water producing area than others. They won't get to the mark where they're going to be put it on rod pump. But I would say we probably got about another 30% to 35% that will be happening over the following quarters. Of course, as we drill in the future, that inventory will increase. But as we stand right now, we're probably looking at about a 35% well count remaining.

Great, thanks. And you also mentioned that you had at one point added, additional workover rigs. And we were talking a little bit about service costs before. What's the day rates look like for workover rig…

They run about $125 an hour. Let's just say they run at eight hour or 10 hour a day to make it easy. You're looking at 12, 15 1250 a day. There's a few add on cost to that, you're probably looking at more like 1500 with all in.

With all the rental…

Well, yeah.

And maybe going back a year ago or a year or two ago, roughly where did that cost then? Just give a sense of how much those might have come down?

You know, back then they were probably running closer to 200 to 225 an hour.

Oh, wow. Okay. So that's a pretty big percentage obviously...

It’s a significant saving, right.

Okay, great. And I don’t think my last just - in the course of looking at different financing alternatives along the way. And I don't really have a strong opinion on it, one way or the other. But did the idea of terming out your debt, you know, some sort of high yield offering, as a way of sort of getting away from the dependence on the credit line was that in the mix of options?

Well, there's actually a considerable number of different options that we were thinking about. When you look back on the sequence of events, I mean, this opportunity presented itself pretty quickly one day and so we felt like we needed to take advantage of it.

Okay, fair enough. Thanks.

Our next question comes from the line of Andrew Bond with Alliance Global Partners. You may proceed with your question.

Good morning, Paul, everyone. Thank you for taking my question.

Good morning, Andrew.

Assuming the current of price current price environment persistence into next year, what might maintenance CapEx budget and development plan look like to hold production flat around 9000 BOE per day, or would you rather anticipate some modest production decline as you indicate you may hold off on picking up a rig and focus more on some of the low hanging fruit blocking and tackling activities, again if the current price environment persists? Thanks.

Yeah, that's a difficult question to ask - to answer right now. But, yes, we probably – it depends on our liquidity and how we're situated going forward. Some of the things that we have spent a little bit less time talking about in this call, then perhaps we should have is all the other different efforts that we're still pursuing to reduce our cost structure. That's not only the lease operating expenses out in the field, but also our G&A. And so we're not done making changes here, reducing our cost. So we're going to be very cost conscious. Yes, we are willing to consider allowing our production to decline next year. Not too much. And we also believe that because of the type of assets we have, that decline will not be like we've pointed out, so are some of the shale producers. But my preference is to in prices, in times like this is to maintain our liquidity. And so yes, we will be willing to spend some capital to maintain it. And so if that requires picking up a rig, we might be willing to do that. But we will, like I said a little earlier, exhaust all of our other opportunities for a higher rate of return, before we actually pick up the drilling rig. We prefer the workover rigs and the other types of projects that we can do to maintain our production.

Okay, got it. That's great color. Thank you. Congrats on the continued free cash flow generation and looking forward to continuing to follow along with the story.

Thank you, Andrew.

[Operator Instructions] Our next question comes from a line of Dun McIntosh with Johnson Rice & Company. You may proceed with your question.

Good morning, Paul.

Good morning.

I apologize if this already been touched on a lot. I'm sure it has. But just if we could talk a little more about kind of the opportunities you're seeing as a way to kind of manage production through either M&A, whether that's smaller deals, or maybe kind of larger corporate transactions with the – I wondered if you're seeing anything from some of the private equity operators out there that might be looking to - might be looking to take someone's currency and get out. Just kind of additional commentary you have around M&A, and larger versus smaller opportunities?

Okay. So where do I begin, there's really a lot I could say. And there's no replacement for cash, let's face it, everybody wants cash. However, at this end of the market spectrum, there's not a lot of people that really want to sell their assets, because they just won't get the valuation that they really believe that they could otherwise receive at a better price point. And so when I look at things, and I look at what has transpired over the last couple of years, and it truly has happened over the last couple of years. We've seen quite a few asset sales failed to close. There are quite a few assets out there in the hands of either private equities or they have gone bankrupt. And we're equitizing the banks. All these different assets that are out there, we also have larger companies that are focused in other areas that have assets that they don't particularly, you know, invest in currently. And so when you look at the myriad of all these potential type opportunities, we believe that we're probably going to need to start off small, build up some momentum, take those properties in and then look for the next one. And for as long as the price environment continues like it is today, we will – well, our plan is to progressively take down each deal we can and progressively get larger and larger and grow the company. Now with respect to our stock and the desire or willingness to accept our stock, every organization is different. Some are willing to consider it. Some are absolutely not willing to consider it because they're more cash focused. And that's just the reality of what we're dealing with. They're all also other people out in the industry that are looking for places to invest capital. They want to put their capital to work. And many of these investors have different requirements for their returns. And so we're looking at all avenues and all opportunities that are facing us. We're looking to structure the deals so that we can attract the capital and attract the asset to grow Ring to meet a certain order of magnitude that also garners more interest in the investment market. And so we believe we need to be bigger, the size of the company is just a little small, we need to be at least what $2 billion in market cap. You know, that's the kind of a goal I have right now. But we have a long way to go. But we believe that there are a lot of opportunities with all these various different groups that we discussed. And so the challenge is, can we structure the deal so that we can bring all the parties to the table and get something done, and then repeat it. Did that answer your question Dun?

Absolutely. Thank you, Paul.

Ladies and gentlemen, we have reached the end of today's question-and-answer session. I would like to turn the call back over to Mr. Paul McKinney for closing remarks.

Thank you, Laura. And thank you to everyone participating in this call. We're excited about what the future holds for Ring Energy and our investors and are encouraged by your support. This is the end of our conference call. Thanks, again.

This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation. Have a great rest of your evening.