Good day, and welcome to the Ring Energy’s First Quarter 2022 Earnings Conference Call. All participants will be in a listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations for Ring Energy. Please go ahead.

Thank you, operator, and good morning, everyone. We appreciate your interest in Ring Energy. We'll begin our call with comments from Paul McKinney, our Chairman of the Board and CEO, who will provide an overview of key matters for the first quarter. We will then turn the call over to Travis Thomas, Ring's Chief Financial Officer, who will review our financial results. Paul will then return to discuss our future plans and outlook before we open the call up for questions. Also joining us on the call today and available for the Q&A session are Alex Dyes, Executive VP of Engineering and Corporate Strategy; Marinos Baghdati, Executive VP of Operations; and Steve Brooks, Executive VP of Land, Legal Human Resources and Marketing. During the Q&A session, we ask you to limit your questions to one and a follow-up. You are welcome to re-enter the queue later with any additional questions. I would also note that we have posted a Q1 2022 earnings corporate presentation to our website. During the course of this conference call, the company will be making forward-looking statements within the meaning of Federal Securities Laws. Investors are cautioned that forward-looking statements are not guarantees of future performance and those actual results or developments may differ materially from those projected in those forward-looking statements and the company can give no assurance that such forward-looking statements will prove to be correct. Ring Energy disclaims any intentions or obligations to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in yesterday's press release and in our filings with the SEC. These documents can be found in the Investors section of our website at www.ringenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday. Finally, as a reminder, this conference call is being recorded. I would now like to turn the call over to Paul McKinney, our Chairman and CEO.

Thank you, Al. Welcome, everybody, and thank you for your interest in Ring Energy. We appreciate you joining us today to discuss our recent results and outlook for the rest of the year. We are executing on our value-focused proven strategy, the results of which can be clearly seen in our operational and financial performance this quarter. We believe our first quarter sales results set a solid foundation for 2022 and are indicative of the increase in revenue and cash flow we anticipate for the remaining quarters this year as long as prices continue to remain strong. As you know, first quarter sales volumes were 8,870 barrels of oil equivalent per day, which exceeded our guidance range by almost 2%. Contributing to this performance were two key operational factors. First, all four of the Central Basin Platform wells we drilled during the first quarter were placed on production sooner than originally anticipated. Second, we were able to complete the installation of certain field compressors, which benefited natural gas sales. We also benefited considerably from higher realized oil and natural gas prices as a majority of our lower-priced oil hedges expired at the end of 2021 and none of our natural gas sales were hedged. The combination of strong sales volumes, higher realized pricing, and our ongoing focus on cost control enabled us to grow adjusted EBITDA by almost 50% compared to the fourth quarter. We generated approximately 36 million of adjusted EBITDA during the first quarter, which was almost half of what we generated in all of last year. Although we increased our activity and placed four Central Basin Platform wells online ahead of schedule, capital spending for the first quarter came in under budget. Our team has done a great job executing our drilling, completion, and capital work-over program, driving further efficiencies in our capital spending. With higher adjusted EBITDA and lower capital spending, we generated almost 13 million in free cash flow this quarter. We used the majority of that to pay down 10 million of debt and we ended the quarter with 71 million of liquidity, which was approximately 16% higher than at the end of 2021, and a 57% increase from the same time last year. With respect to our development initiatives, we decided to take advantage of a strong commodity price outlook and implement a continuous one-rig drilling program during 2022. Our program is designed to remain within cash flow and drive production, revenue, and adjusted EBITDA growth, and to significantly lower leverage ratio by the end of the year. As in the past, we are targeting our highest rate of return inventory across our Central Basin Platform and Northwest Shelf acreage. As you know, we initiated our 2022 development campaign in late January and drilled six wells in the first quarter. This included four wells in Central Basin Platform and two wells in the Northwest Shelf with all wells having 100% working interest. As I mentioned, the four Central Basin Platform wells were placed on production in the first quarter, and we have since completed and brought online the two Northwest Shelf wells. We are encouraged by the results we have seen to date from our 2022 drilling program. Leveraging our learnings from last year, we remain squarely focused on the geology, selecting the best landing zones, and improving our completion methods. We are also continuing our program to convert wells from downhole electrical submersible pumps to rod pumps, a capital work program we call CTRs. We performed four CTRs in the Northwest Shelf in the first quarter. As we discussed in the past, the long-term benefit of our targeted CTR program allows us to significantly reduce our operating cost with lower electricity usage and considerably lower future repair costs. These lower operating costs lead to larger economic lives of the wells and improve the ultimate recovery of oil and gas reserves. Looking forward to the second quarter, we expect to drill eight to ten wells while completing and placing on production seven to nine wells. For the full year, we are still planning to drill between 25 wells and 33 wells and complete and place online between 25 wells and 30 wells. Of course, we will continue to retain the ability to adjust our drilling and other capital spending program to reflect any material changes in commodity prices. So, with that, I will turn over to Travis to discuss our financial results in more detail. Travis?

Thanks, Paul, and good morning everyone. My comments today will primarily focus on our financial position and sequential quarterly results. For detailed discussions concerning comparisons to last year's first quarter, please see our press release and 10-Q we filed yesterday with the SEC. During the first quarter of 2022, we sold 676,000 barrels of oil and 732,000 Mcf natural gas, for a total of 798,000 Boe. This is compared to sales of 715,000 barrels of oil and 762,000 Mcf of natural gas or a total of 842,000 Boe for the fourth quarter of 2021. First quarter realized pricing was $93.80 per barrel and $6.49 per Mcf or $85.41 per Boe. During the fourth quarter, we had realized oil pricing of $76.35 per barrel, natural gas pricing of $6.65 per Mcf, or $70.85 per Boe. Our first quarter average oil price differential from NYMEX WTI was a negative $0.90 per barrel for the first quarter versus a negative $1.12 per barrel for the fourth quarter of 2021. Our average natural gas price differential from Henry Hub for the first quarter was a positive $1.81 per Mcf, compared to a positive differential of $1.85 per Mcf for the fourth quarter. This combined result was first quarter revenues of $68.2 million that were 14% higher than fourth quarter 2021 revenues of $59.7 million. Looking at the more significant expense line items on the income statement, LOE was $9 million or $11.22 per Boe, compared to $7.7 million or $9.12 per Boe for the fourth quarter of 2021, primarily due to inflationary cost pressures and a higher than usual amount of workovers performed to return wells to production. Gathering, transportation, and processing, or GTP cost decreased $1.3 million from $1.4 million in the fourth quarter 2021, primarily due to lower gas sales. Production taxes were $3.2 million versus $2.8 million in the fourth quarter with a tax rate remaining steady at 4.7% for both periods. DD&A was $9.8 million, compared to 10.5 for the fourth quarter of 2021. It was substantially unchanged on a Boe basis. Cash G&A, which excludes share-based compensation, was flat at $4 million for both periods. Interest expense was $3.4 million versus $3.5 million for the fourth quarter with a decrease due to a lower average daily borrowing balance on RBL. During the first quarter, we posted net income of $7.1 million or $0.06 per diluted share, excluding the estimated after-tax impact of pre-tax items, including a $13.5 million for non-cash unrealized losses on hedges and $1.5 million for share-based compensation expense. Our first quarter adjusted net income was $22.3 million or $0.22 per share. This is compared with fourth quarter 2021 net income of $24.1 million or $0.20 per diluted share. Excluding the after-tax impact of pre-tax items, including a $15.2 million for non-cash unrealized gains on hedges and approximately $900,000 for share-based compensation expense, our fourth quarter adjusted net income was $9.9 million or $0.10 per share. As of March 31, we had $280 million drawn on our revolving credit facility and liquidity of $71 million, including $2 million of cash and $69 million available on the revolver, which reflects a reduction for letters of credit. We were pleased to pay down the facility by $10 million in the first quarter and look forward to further debt reductions during the remainder of 2022. To sum it all up, we had a great quarter with the addition of approximately $36 million of first quarter adjusted EBITDA, our trailing 12-month EBITDA increased to $100 million. With $280 million outstanding on the EBL, the math is simple to calculate our leverage ratio of 2.8x versus 3.5x at year-end. It looks even better when we annualize the first quarter, which would bring our leverage ratio to under 2x. I would also note that in early April, a total of 6.5 million of our common warrants were exercised at a price of $0.80 per warrant. Accordingly, our second quarter results will reflect the issuance of 6.5 million shares of common stock and a receipt of $5.2 million of cash. There are currently approximately 23 million common warrants that remain unexercised. Turning to our outlook, we continue to expect full-year 2022 sales volumes of 9,000 to 9,600 Boe per day, which is a 9% year-over-year increase using the midpoint of our guidance. We continue to anticipate total capital spending of $120 million to $140 million for full-year 2022, which includes the estimated cost to drill 25 wells to 33 wells and complete 25 wells to 30 wells, primarily in the Northwest Shelf. Our full-year capital spending outlook includes targeted well reactivations, workovers, infrastructure upgrades, and continuing our successful CTR program in the Northwest Shelf and Central Basin Platform. Also included is anticipated spending for leasing, contractual drilling obligations, and non-operated drilling, completion, and capital workovers. As Paul noted, our 2022 capital spending program assumes a favorable commodity pricing environment. If pricing were to pull back materially, we have the flexibility to reduce capital spending as necessary. For the full-year 2022, we anticipate LOE of $10.90 to $12 per Boe, and GTP cost of $1.60 to $2 per Boe. For the second quarter of 2022, we are targeting sales volumes of 9,000 to 9,400 Boe per day. The midpoint of our guidance represents a 4% increase from the first quarter and more fully reflects the benefit of the continuous drilling program that we initiated in late January. As Paul discussed, we expect to drill 8 wells to 10 wells and complete and place on production 7 wells to 9 wells during the second quarter. We also expect LOE of $10.90 to $12 per Boe and GTP cost of $1.70 to $2 per Boe for the second quarter. In terms of our hedge position, we were pleased to have the majority of our lower price hedges roll off at the beginning of the year. As reflected in our first quarter results, this provides us with the opportunity for substantially higher revenue and operating cash flow in 2022, assuming a continued strong oil price environment. I will now turn it back to Paul for his closing comments before we answer questions.

Thank you, Travis. As we have discussed today, we have seen the initial benefits of our transition to a continuous one-rig drilling program supported by stronger realized prices for oil and natural gas. We expect production and operating cash flow will continue to steadily grow throughout the remainder of 2022, as long as hydrocarbon prices remain strong and we continue to bring more wells online. Complementing these efforts are our ongoing initiatives to drive further efficiencies in our operating cost structure. Consistent with the past, we plan to use our operating cash flow to fully fund our capital investment plans and further reduce debt. We are targeting a leverage ratio of less than 2x by the end of this year, which is a substantial improvement from just under 3.5x at the end of 2021. To sum things up and based on our current industry outlook, we expect 2022 to be a good year for Ring Energy and stockholders. We remain focused on finding the right acquisition opportunity and as you have heard me say in the past, we believe that by increasing size and scale, we can provide greater stability to our production and earnings and place a company on the radar so to speak with a greater audience of potential investors. Our commitment though is to our existing stockholders and any transaction we completed using equity will be strategic and accretive on a debt adjusted per share basis. We look forward to keeping everyone apprised of our progress in this regard. With that, I will turn the call back to the operator and we look forward to answering your questions.

Thank you. And the first question will be from Jeffrey Campbell from Alliance Global Partners. Please proceed.

Good morning. Paul, in the press release, LOE discussion noted service cost inflation and on that front, we've heard from some quarters that even long-term steel and sand contracts are not being delivered due to lack of supply or railroad constraints. I wondered if you're hearing of any similar challenges in your operating area generally and of course, regarding specific status on supply necessary services and materials?

Yes. At this point, we have not experienced any supply disruptions. We are though experiencing significant inflationary pressures with respect to steel and also the completion costs. Following up on that, we're also seeing increases in electricity and some other things, but directly answering your question, Jeff, with respect to the supply chain and our ability to continue our operations, we have not experienced any interruptions at all. Marinos, do you have any other comments you'd like to make?

We have comfortably secured casing to get us through October. We're in the process of securing October and beyond, and the sand is an issue that we're fighting with everyone else, but as of right now, it hasn't been an issue. We also want to emphasize that the nature of our completions doesn’t require as much volume as some of the other plays in the Delaware or the Midland basin. So, that puts us in a little bit of an advantage in that regard in terms of the volume that we require for our operations.

Okay, thank you. I appreciate that last color. And the press release noted Ring’s leverage reduction as you continue to pay down debt and increase production and EBITDA, do you have a leverage target in mind that would enable you to either add a rig if commodity prices are supportive or transact in the market if an accretive deal was available in late industrial sense?

Yes, that's a very complex question, Jeff. And so yes, at this stage right now, when we look at our projected cash flows at current industry strip prices, we are balancing the needs to keep our capital spending program within our cash flow, but also we have very specific targets associated with reducing our debt. Anytime you start or pick up another rig, you'll run that rig for a while and you're incurring costs and until the production gets high enough where they're starting to pay those costs back down, you can, you know with a rig you can very quickly spend a lot of money. And so, before we pick up another rig, our cash flows, balancing the cash flows, higher or more sustained prices or whatever, need to be there. So that we can follow through on our commitment to ensure that we continue to strengthen the balance sheet. I mean, ultimately, our goal is a fortressed balance sheet. And because that really does a lot of good for us from the standpoint of strategically taking advantage of opportunities that may be presented in the marketplace. It's also the proper way to use the liquidity you have and the relationship you have with your banks to pursue opportunities with a clear overview of paying that debt down but utilizing the capacity on your revolving credit facility just for those strategic reasons. Did that answer your question, Jeff?

Yes. It did. Actually that was great color. I appreciate it.

Thank you. And the next question will be from Neal Dingmann from Truist Securities. Please go ahead.

Good morning, guys. Hear me, alright?

Good morning, Neal. How are you?

Good. Good. Hey, Paul, my question for you and Marinos on the operational side, specifically, could you discuss a bit, you guys continue to be pretty active both on the platform and the shelf with a nice combination of both, which is great to see. I’m just wondering, could you all speak to just how you're seeing how they sort of stack up versus each other right now, when you look at returns of each? I think both are pretty exciting and then maybe speak to the workover opportunities in each of the areas?

Yes, sure. I’ll give a first stab and I'll turn it over to my expert. What we've experienced as a result of the work that our Geoscience and engineering teams have done, we've now placed our Central Basin Platform wells in a category that when you look at the range of outcomes, it's hard to distinguish the difference between the economic returns of both the Central Basin Platform and Northwest Shelf. They're so close. Typically, the Northwest Shelf wells might be a little bit better, but we've had such really good results in the Central Basin Platform and we’re really pleased in that regard. And so, that's really all I'll say concerning that. I'll turn the rest over to you, Marinos.

I really don't have anything to add to that, Paul. I mean, you answered it perfectly.

And so, yes, when we first came on board, we saw the legacy acreage down there. We felt obligated to spend the time to really study it hard. And we put a lot of effort into that. And then last year, when we drilled those first three wells, it was kind of a test program. We wanted to see what we could do. And we were very pleased with the results. And so, right now the drilling program between the Northwest Shelf and Central Basin Platform has more to do with balancing the cost associated with our development. So, let me explain on that. When we drill our first four wells down in the Central Basin Platform and made the decision to go back up north, when you bring these new wells on, you get a lot of production and our infrastructure there to dispose of the water can only handle so much. Right? And so, by going up to the Northwest Shelf, drilling some wells there and then coming back to the Central Basin Platform later in the year that allows us earlier wells to decline and minimizes the investments necessary for water disposal. So, it's really an operational management issue as to where we're going to have a rig and at what time. And so, we're balancing a lot of other things in addition to just the performance of the individual wells. It also has a lot to do with just managing your overall cost. Did that give you the color you're looking for?

You did, and you actually led, kind of two other pieces I was going to ask you about, just on infrastructure takeaway is one rig or if you ever decided on two rig to see if you have, how that sort of sits on both the plays and then just you, on logistically, when you all are looking to ensure you continue to keep that rig, make sure you can get drill pipe in each of the areas. Could you just, sort of hit as things sort of progress, things obviously are tight on both the service and takeaway side? Just you know, how you all sit on both those sides for in each of the areas?

Yes, for us to step it up to another rig, first of all, we need to have more cash flow. So, if you look at the rest of this year and the way our projections are, with the one-rig program, we're spending money very quickly. Okay? And so you don't want to out run your cash flow. So, we intend to pay down debt every quarter. We may not be able to do that just because we're managing those issues, but the other things that you brought up associated with the supply chain, if we were to pick up a second rig that would significantly increase the long lead time purchases necessary to keep that rig going, sourcing the sand, getting the frac crews all lined up. So that's another step change in that regard. And then at the same time, it goes back to the infrastructure that we had to handle the water and the production. And so at this stage, right now we're not intending to pick up a second rig this year, I can't really imagine the circumstances that would cause us to do that. Now, going into 2023, that could happen, but the last point that you brought up associated with potential acquisitions, we do have our eyes on several different opportunities out there in the marketplace. And those opportunities may or may not come with existing running rigs and capital programs. And so with an acquisition, it wouldn't, it shouldn't surprise shareholders that we would keep the second rig running, depending on the size and the opportunities and the economics of those acquisitions.

Paul, if I can quantify on the infrastructure that Paul was mentioning, our current capital budget guidance mentioned that about 82% of that will be D&A and equipping less than 10% of that is dedicated to infrastructure, the rest is, so more than 90% is dedicated to drilling and completing wells and having production come online. And we did a tremendous effort to make sure that in our scheduling we would ensure that we minimize our infrastructure costs and adding another rig would possibly need us to change directions there.

Yeah. That's good color.

No, great color from both. No, that's exactly what I was looking for. Nice quarter. Thanks guys.

Thank you.

The next question is from Noel Parks from Tuohy Brothers. Please go ahead.

Hi, good morning.

Hey, good morning, Noel. How are you?

Real good. Thanks. Just a couple of things. I was wondering and you just talked about all the effort you put into the logistics of the drilling completion plans and the pace. Just wondering, right now, are you having any issue with the sort of pairing up of the frac teams arriving when you want them to according to your plans? Do you have to leave like more room than usual or is that going fairly smoothly these days?

Noel, I'm really glad you asked that because we're actually really proud about the way we schedule things out. We gave a couple of weeks of leeway between the drilling rig leaving the location and us being able to get the frac crews to show up and we've actually exceeded that in every one of the eight wells we've brought online so far this year, including seven quarters. So, we're very proud of that. Our team has done a great job, being in constant communication with the completion service companies and it has not been an issue so far.

Terrific. And I was wondering at this point was this a terrific price environment we have, is the sort of furthest out here of the Central Basin Platform inventory reasonably economic even at these prices? Especially at these prices?

Yes. No, everything that we are drilling this year, again, if you look at what we did last year, we’re taking the same approach this year. We're really looking at the various risks associated with each of the drilling locations. We're selecting the highest risk-adjusted rate of return wells to drill. During this time period, we feel compelled to squeeze every last dollar out of every investment we make to increase our production so we can strengthen the balance sheet. And so, it's all about efficiency. We do have other wells, undeveloped opportunities in our portfolio that don't have the returns of the wells that we're drilling. And I'll just bring it up, the Delaware Basin has several PUDs on the books that, you know, they’re economic at today's price, but they're not as economic as the ones that we're drilling. So, we feel compelled to make sure that we optimize every last investment and so that's what we'll continue to do.

Got it. And I'm just wondering also against your forecasting now that we're more than a third of the way into the year, have labor cost expectations you had been more or less in line with reality? And I'm just curious on the shelf and the platform, are services pretty much at full utilization now, both fracs and rigs?

I'll take the first part of that question. I'll turn the rest over to Marinos, but when we planned our program this year, we had already been experiencing what we consider to be high levels of inflationary pressure on all the products and services and supplies and equipment that we need to complete our programs. And so, we tried to build that into our program. But it's hard to predict that, and it kind of goes back to one of their earlier questions that we answered earlier, the pressures that we're seeing on steel prices have not let up, you know competition for sand is causing prices and the availability there to be a challenge. And labor costs are going up very fast because most of the service companies that we employ are having difficulty attracting people back to the oil patch. I mean after the pandemic, there was a large percentage of the labor force that left the industry. And to attract them now, you're going to – what we're seeing happen is that salaries are going up. They're sweetening their benefit packages. They're doing all the things they can do to get the talent back, and so we're dealing with crews that are not as experienced. So, you can't have the same efficiencies from these crews, from these crews that used to run 24 hours are now only running during the daylight hours. And so that causes our programs to take longer. So, we don't get the production on as soon as we otherwise would and it is also costing more. I don’t know if there’s any more you want to add to that?

No, that’s perfect, Paul, and we've built in a lot of those, but just for an example, our completion cost, we bid out all our fracs and I'm not going to give out the numbers, but percentage-wise, the second best bid is 25% higher than the best bid and the next bid is another – is 50% higher than the best bid. We start out with of course the best bid company and to the second part of your question, all the services are pretty much 100% utilized in the Central Basin Platform and the Northwest Shelf. So, that could give us a big range on the cost of the wells and we've tried to adjust for that, but it could, you know if we end up having to go with companies that that are higher cost in order to get the work done, that might start changing our costs.

And the funny thing about that is that oftentimes when you bid one job out versus another, it's not the same people coming in with a low cost, it seems to be more associated with the availability of their crews, and how busy they are and the inventory of the chemicals or sand or the other things that they need to complete a job. And so, there's a lot of volatility, not only in the oil and gas price prices that we're experiencing, but we're seeing a lot of volatility associated with the relationships we have with the various service providers because they have shortages of supplies and inflationary pressures that they're dealing with. And so it's very interesting times. I will second what Marinos just said about our teams, our drilling crews, our completion crews, and their scheduling. They've done a great job of getting out ahead. We knew that we had these headwinds leading into this work program. And so we started early, we were calling on relationships and it's a benefit of all those things that allowed us to maintain the efficiency and keep our programs going like we have.

Right. Well, high-class problems at $100 oil. So, I guess we’ll take it.

There you go.

Thanks a lot.

Thank you.

At this time, there are no further questions. So, I would like to turn the conference back over to Paul McKinney, Chairman and CEO for any closing remarks.

Thank you, Chad. And thank you all of you that tuned in today to listen to what we had to say. We are very excited about this year. We have a lot of really good things going on. Product prices are high. We do have our challenges in our operational program, but we're really, really enjoying the benefits of all these things because we have a really good year going. And so, stay tuned, and we'll keep you informed with what we're doing.

Thank you, sir. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.