Ring Energy, Inc. (AMEX:REI) Q3 2024 Earnings Call Transcript

Ring Energy, Inc. (AMEX:REI) Q3 2024 Earnings Call Transcript November 7, 2024

Operator: Good day and welcome to the Ring Energy Third Quarter 2024 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note, today’s event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations for Ring Energy. Please go ahead.

Al Petrie: 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 third quarter of 2024 as well as our updated outlook; who will then turn the call over to Travis Thomas, Ring’s Executive VP and Chief Financial Officer, who will review our financial results. Paul will then return with some closing comments 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; and Shawn Young, VP of Operations. During the Q&A session, we ask you to limit your questions to one and a follow-up.

You are welcome to reenter the queue later with additional questions. I would also note that we have posted an updated corporate presentation on 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 the forward-looking statements. Finally, the company can give no assurance that such forward-looking statements will prove to be correct. Ring Energy disclaims any intention or obligation 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 located 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 yesterday’s earnings release. 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.

Paul McKinney: Thanks, Al. We appreciate everyone joining us today and your interest in Ring Energy. Before I begin to discuss our specific third quarter results, I would like to first take a high level view and consider our overall third quarter accomplishments in relation to the first half of this year, as well as our year-to-date performance as compared to 2023. As a reminder, we closed the all cash acquisition of Founders Central Basin Platform Assets in August of last year. Similar to our purchase of Stronghold CBP Acreage in 2022, the Founders acquisition was immediately accretive and allowed us to strategically expand our core operating area, further increase our inventory of low risk, high rate of return drilling locations and improve capital allocation flexibility, capture operating G&A cost synergies and most importantly, maximize our ability to generate adjusted free cash flow and pay down debt at a faster rate than we were able to do so on a standalone basis.

Our year-to-date performance in 2024 has shown important growth across multiple key metrics including an 11% increase average per day total sales volume over the same period in 2023. When considering the 2% decrease in per BOE all cash operating costs achieved year-to-date, that was partially offset by the 3% reduction in total realized commodity prices year-to-date. The result was 7% growth in adjusted EBITDA year-to-date. When combined with our continued focus on capital discipline, our year-to-date adjusted free cash flow increased 34%. Again, our 2024 third quarter and year-to-date results have clearly benefited from the Founders acquisition. Having said that and consistent with our efforts in — with the 2022 Stronghold acquisition, we have strengthened our balance sheet and are accelerating our ability to pay down debt.

At the end of the third quarter, we had $392 million of debt, which is $5 million less debt than we had the quarter prior to closing the Founders acquisition last year, yet we have over 2,800 barrels of oil equivalent per day of additional production. This clearly demonstrates that Ring Energy is creating value for our stockholders and that our value focused proven strategy is working. Now, turning our attention specifically to our third quarter performance. We are pleased to report strong performance for the period, which was in line with our expectations. We posted record sales volume for the period as well as year-to-date. During the quarter, we also successfully executed our drilling and completion program and sold certain non-core high operating cost vertical wells and related assets to an unaffiliated buyer.

We utilized the proceeds from the sale to help pay down $15 million of debt during the third quarter. Similar to the second quarter, our record third quarter sales volumes exceeded the high end of our guidance, while operating expenses and capital spending were both near the midpoints of our guidance ranges. We believe we remain well positioned for ongoing success for the remainder of the year and into 2025. The primary driver of our record sales volume in the third quarter was a continued strong return from our drilling program and the outstanding performance of our operating team maintaining our existing production. Result for the period was a sale of 20,108 barrels of oil equivalent per day, of which oil sales were 13,204 barrels of oil per day.

Lease operating expenses or LOE during the third quarter were $10.98 per BOE, which was essentially at the midpoint of our guidance range. As compared to our expectations, third quarter LOE per BOE results primarily reflected higher expense workover costs. Higher than anticipated record sales volumes and expected LOE per BOE levels were partially offset by a decrease in realized third quarter oil and BOE sales pricing of 7% and 12% respectively. The result was adjusted EBITDA of $54 million which was less than the $66.4 million generated in the second quarter. However, as I mentioned earlier, year-to-date adjusted EBITDA growth was 7%. Looking at CapEx, we invested $42.7 million which was near the midpoint of guidance versus the $35.4 million in the second quarter.

In the third quarter, we drilled seven horizontal wells, three in the Northwest Shelf and four in the Central Basin Platform. Five wells were completed in the third quarter and the other two came online early October. In addition, we drilled and completed six vertical wells in CBP South including three in Ector County and three in Crane County. Total capital spending also included capital workovers, infrastructure upgrades and leasing. Adjusted free cash flow was $1.9 million for the third quarter, which represented the 20th consecutive quarter of positive adjusted free cash flow for the company. Impacting adjusted free cash flow was a previously mentioned timing of capital projects that resulted in a $7.3 million increase in CapEx in the second quarter.

Also impacting adjusted free cash flow for the third quarter was certain changes in working capital balances that Travis will discuss in more detail later. Turning to the balance sheet. As a reminder, we sold non-core assets for $5.5 million in cash. An important point to make is that this sales price represents 5.6x estimated next 12 months cash flow. We view this as an attractive valuation for our stockholders. The sale proceeds were used to help pay down $15 million of debt in third quarter, which led to debt reduction of $33 million year-to-date and $63 million since the closing of the Founders acquisition last August. As a result, we ended the third quarter with liquidity of $208 million and a levered ratio of 1.59x. Regarding our guidance for the year, we are updating our full-year 2024 outlook to reflect our third quarter performance and to account for the fourth quarter impact of the sale of non-core assets.

We plan to drill four to six horizontal and four to six vertical wells in the fourth quarter with two horizontal wells and one vertical well drilled and completed to date. As a reminder, during October, we also completed and placed on production two wells drilled in the latter part of the third quarter. As in the past, we retain the flexibility to react to changing commodity prices and market conditions, as well as manage our quarterly cash flow. Our drilling program remains focused on organically maintaining or slightly growing our oil production. Our updated full-year 2024 production guidance is 13,250 to 13,450 barrels of oil per day and 19,500 to 19,800 barrels of oil equivalent per day. Regarding the fourth quarter specifically, we expect total sales volumes of 19,200 to 20,000 barrels of oil equivalent per day and oil production to range between 12,950 and 13,550 barrels of oil per day, resulting in a 68% oil mix.

With that, I will turn this over to Travis to provide more details and then return to closing comments before we open the call for questions. Travis?

Travis Thomas: Thanks, Paul, and good morning, everyone. As Paul discussed, we posted third quarter operational and financial performance that met or exceeded our most recent guidance and initial expectations. Outstanding execution by our team across the board resulted in record total sales volumes and in line operating and capital spending levels. This was partially offset by more than 10% decrease in the total realized pricing from the second quarter. Cash flow generated by our core assets combined with the proceeds from the sale of our non-core assets contributed to a $15 million pay down of debt in the third quarter. As I’ve said in the past and echoing Paul’s viewpoint, balance sheet improvement has and will remain a top priority for the company.

With that overview, let’s look at the quarter in more detail. We sold 13,204 barrels of oil per day and 20,108 Boe per day. This represents a 3% decrease and a 2% increase respectively from the second quarter with our record third quarter BOE sales volumes exceeding the top end of our guidance. The primary driver of our overall sales volumes growth in the third quarter was the positive impact of our drilling program as well as the improved gas takeaway and NGL realizations. Our third quarter average crude oil price differential from NYMEX WTI futures pricing was a negative $0.56 per barrel versus a negative $0.61 per barrel for the second quarter. This was mostly due to the Argus CMA roll that increased $0.31 per barrel offset by the Argus WTI WTS that decreased by $0.17 per barrel on average from the second quarter.

Our average natural gas price differential from NYMEX futures pricing for the third quarter was a negative $4.43 per Mcf compared to a negative $4.31 per Mcf for the second quarter. Our realized NGL price for the third quarter averaged 11% of WTI compared to 12% for the second quarter. The result was revenue for the third quarter of $89.2 million a 10% decrease from the second quarter primarily driven by lower overall realized pricing. We continue to target higher oil mix opportunities as oil accounted for 101% of total revenue, while it was only 66% of total production. In short, our positive NGL sales were not quite able to fully offset our negative gas sales resulting in net negative of $1.2 million. As noted in the third quarter, we continue to see negative realized pricing for natural gas.

While the majority of our GTP costs are reflected as a reduction of the sales price, the larger impact on our realized natural gas pricing reflects the continued product takeaway constraints we have seen in the basin. The good news is additional third-party takeaway capacity is now in line with the Matterhorn Express Pipeline in West Texas, which started flowing gas in October and is expected to alleviate pricing pressure going forward. Moving now to expenses. LOE was $20.3 million or $10.98 per Boe versus $19.3 million or $10.72 per Boe for the second quarter. Echoing Paul’s comments, we are pleased to see LOE come in substantially at the midpoint of our guidance of $10.50 to $11.25 per Boe. Cash G&A, which excludes share-based compensation was $6.4 million compared to $5.6 million for the second quarter with the increase primarily due to severance payments associated with the reorganization of field leadership, higher regulatory consulting fees due to reporting requirements for newly implemented emissions regulations and an adjustment to the annual incentive plan accrual.

Our third quarter results include a gain on derivative contracts of $24.7 million versus a loss of $1.8 million for the second quarter, of which $26.6 million was an unrealized gain, offset by $1.9 million of a realized loss. As a reminder, the unrealized gain/loss is just the difference between the mark-to-market values period-to-period. Finally, for Q3, we reported net income of $33.9 million or $0.17 per diluted share compared to second quarter net income of $22.4 million or $0.11 per diluted share. Excluding the estimated after-tax impact of pretax items, including non-cash unrealized gains and losses on hedges and share-based compensation expense, our third quarter adjusted net income was $13.4 million or $0.07 per diluted share, while second quarter adjusted net income of $23.4 million or $0.12 per diluted share.

We posted third quarter 2024 adjusted EBITDA of $54 million versus $66.4 million in the second quarter, with approximately $8 million of the decline associated with lower sequential realized pricing. During the third quarter, we invested $42.7 million in capital expenditures. This was within our guidance range of $35 million to $45 million, with each of the wells drilled and completed and coming online within guidance. Note that we had two DUCs at the end of the third quarter that were completed in early October and are now online. Adjusted free cash flow was $1.9 million versus $21.4 million for the second quarter. As Paul mentioned, impacting the third quarter adjusted free cash flow was $7.3 million higher capital spending and $12.3 million less in EBITDA compared to the second quarter.

We paid down $15 million of borrowing on our revolver in the third quarter, $33 million year-to-date and $63 million, since closing the Founders acquisition in late August. At September 30th, we had $392 million drawn on our credit facility. With the current borrowing base of $600 million, our liquidity and availability was $208 million with a leverage ratio of 1.59x. The difference between our adjusted free cash flow and the debt paydown was mostly due to the $5.5 million in cash proceeds from the previously discussed sale of non-core assets, a $6.8 million change in working capital and a $1.2 million reduction in cash on hand. Moving now to our hedge positions. For the last three months of 2024, we currently have approximately 600,000 barrels of oil hedged or approximately 48% of our estimated oil sales based on the midpoint of our guidance.

We also have 0.5 Bcf of natural gas hedged or approximately 32% of our estimated natural gas sales based on midpoint. For a detailed breakout of our hedge positions, please see our earnings release and presentation, which included the average price for each contract type. Looking at our guidance. The balance of the year reflects the impact of the production and operating costs associated with the non-core assets sold. As such, our average daily sales volume guidance for the full-year 2024 have been updated to crude oil sales volumes of 13,250 to 13,450 barrels of oil per day and Boe sales volumes of 19,500 to 19,800 Boe per day or 68% oil. In addition, for the fourth quarter, we are providing a sales outlook of crude oil sales volumes of 12,950 to 13,550 barrels of oil per day and BOE sales volumes of 19,200 to 20,000 BOE per day at 68% oil.

For CapEx, we now expect to spend between $147 million and $155 million on our full-year 2024 development program, which is in line with the midpoint of our previous full-year guidance. In addition, we are providing an estimate between $33 million and $41 million for the fourth quarter. We now fully anticipate full-year 2024 LOE of $10.70 to $11 per Boe and are providing guidance of $10.75 to $11.25 per Boe for the fourth quarter of 2024. So with that, I will turn it back to Paul for his closing comments. Paul?

Paul McKinney: Thank you, Travis. Our solid results for the third quarter follow our strong performance in the first half of 2024 which we view as a direct reflection of the merits of our proven and disciplined strategy designed to maximize free cash flow generation and enhance the balance sheet through further debt reduction. We are doing this by profitably growing the business through the execution of a combination of targeted organic and external opportunities with the ultimate goal of providing a sustainable return of capital to stockholders. As I mentioned in our earnings release, we look forward to the results of testing new opportunities designed to unlock new producing zones on our existing acreage. These investments represent a new phase of potential inventory growth for our company through seeking to identify and develop new hydrocarbon resources organically.

We will share more on this in the future. In my closing comments on the past calls, I have tried to address the key questions related to our strategy we have heard from our institutional and individual stockholders. Following that practice, I will do the same today. The first point we’ve heard relates to paying down debt and the third quarter provides a good example of our commitment in this regard. As discussed earlier, we paid down another $15 million of debt with year-to-date debt reduction coming in at $33 million. Clearly, oil prices have a huge impact on our ability to pay down debt. Having said that, if oil prices are sustainably lower than current levels, we will reduce capital spending to maintain production levels, so we can meet our debt reduction goals.

Debt reduction will continue to be a key focus until we reduce our leverage ratio below 1. Another thing we’ve heard and would like to discuss is the low valuation of our stock in the recent and current marketplace. As many of you know, recent high profile M&A activity has occurred in our operating areas, reflecting that the upside in the CBP has long been overlooked. Up until the summer, drilling activity in the CBP in the southern part of the shelf has been dominated by us and a handful of other smaller operators. That appears to be changing with Apache’s September disposition of its conventional assets in the CBP and Northwest Shelf areas for $950 million. We summarize important deal metrics on Slide 15 included in our updated deck posted on our website.

The Apache assets had estimated net production of 21,000 barrels of oil equivalent per day, of which 57% was oil. The sales price equates to approximately $45,200 per daily flowing BOE. We also believe that because some of the APA assets involve enhanced recovery using CO2, those assets generally have higher LOE costs and lower margins than Ring’s assets. When using this metric for comparison and assuming third quarter average production of 20,108 barrels of oil equivalent per day for Ring Energy and Apache’s transaction valuation of approximately $45,200 per daily flowing BOE, Ring’s indicative stock price should be approximately $2.61 per share. Another point that can be made regarding the APA production metric is that Ring’s oil mix is 68% is considerably higher, which could suggest a higher indicative price.

When considering that our LOE is most probably lower, leaving higher margins, this too suggests that the indicative price of $2.61 per share could be considered conservative. Another valuation metric comparison we have observed to be common in our industry is a multiple of the estimated next 12 months cash flow. A multiple of 4x to 5x has been considered in the past as a reasonable range. If we assume approximately 4.5x estimated next 12 months cash flow, as a reasonable cash flow metric, Ring’s indicative stock price should be approximately $3.45 per share using analyst consensus estimates for full-year 2024 cash flow. Clearly, the first comparison suggests that Ring’s current marketplace valuation is trading at levels significantly less than the value industry is willing to pay to acquire similar assets.

The second comparison suggests a valuation based on common 12 months trading metrics is a reasonable way to value Ring stock. In short, I sincerely believe that Ring Energy stock is currently trading at a very large discount and investors have an incredible opportunity before them to acquire our stock. So with that, we will turn this call over to the operator for questions. Rocco?

Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Today’s first question comes from Neal Dingmann at Truist. Please go ahead.

Q&A Session

Neal Dingmann: Good morning guys. Good details. Paul, my question is just a little bit on what you were touching about earlier, but it’s really on inventory. I’m just wondering, again, when you look at out there right now, maybe give us an idea of in years, what you think you have? And again, when you start looking at both vertical and the horizontal opportunities, has that extended inventory? And again, maybe just — I’m trying to get a sense of how that runway has changed because of drilling both these type of wells.

Paul McKinney: Yes, very good. That’s a very good question, Neal. And if you look at our corporate deck, we estimate that we’re around 450 opportunities in our inventory deck. And so we don’t have — just to be quite frank, we don’t have that 10 or 15 years of running room that many of the large companies in the Delaware and Midland Basin have. And so that’s part of the reason why we’re so concentrated on acquisitions. But I also shared both in the release and on this call today that we are entering a new phase of development. We have built up our geoscience and engineering team to start organically identifying opportunities that we can stack into our inventory. I believe that some of the capital we’re spending this quarter could actually contribute to that.

And so I think you’re going to see basically two ways to win, so to speak, in terms of building inventory and expanding that inventory and through A&D and also through organic means. And so right now, we have the short and medium term, very well taken care of, but we don’t have that 10-year horizon that other people have. And so that’s part of the reason why we’re so focused on expanding our ways to win in that regard. Did I answer your question, Neal?

Neal Dingmann: Yes, exactly. And then just lastly, how different — again, you’re in the platform, you’ve added some interesting shelf. How different either on existing, or when you’re looking for M&A, how different now do you all — I’d love to hear for you or Alex or the team, how different are you viewing sort of opportunities, both existing and potential opportunities between the platform and the shelf? I mean is it now relatively the same, or just how different — how are the economics there?

Paul McKinney: Yes. So I’ll let everybody kind of chime in on that. I think the economics are — have actually improved this year because I think we’ve seen kind of a pullback from the high watermark on capital cost for the goods and services. So the cost to drill our wells and complete our wells has come down slightly. So our economics have actually improved if the oil price is the same. But as you know, the volatility we’ve seen also puts a lot of speculation into what are the oil prices that we can depend on to help pay back those investments. So — but from that standpoint, I think the economics are what they are, and they’re going to be subject to oil prices. I do believe that there will be a time when activity levels in the Permian Basin will increase.

And so I think some of the savings we’re seeing may evaporate depending on what future activity is. But with respect to the inventory and the opportunities out there, I think this summer was the first wave of dispositions from some of these larger companies. And I believe that we’re going to continue to see dispositions hit the marketplace that fit the strategy that we’re pursuing. And I think that there will be more opportunity hitting the street that we ourselves can take down. And so I really, I’m optimistic about what the future looks like in terms of building inventory, the future economics. We’ve demonstrated very clearly that we know how to drill these wells and complete them very efficiently and generate a strong return for our stockholders.

Alex, do you want to chime in on that?

Alexander Dyes: Yes. Thanks, Paul. Neal, I think we have a slide in the IR deck on Page 27 that really proves that point that Paul is talking about. In D&C, our cost structure has gone down. And so our — the question we always get is what are the investments in the vertical versus the horizontals. And as we’ve lowered our cost structure in both of those places, it looks a lot more robust. And so we continue to do a lot of blocking and tackling and trying to add inventory via acreage add-ons or bolt-ons, but we see the landscape moving forward that we’ll continue to try to negotiate one-off deals with other offset operators. Did we answer that question for you, Neal?

Neal Dingmann: Yes, thanks guys.

Operator: Thank you. And our next question comes from Jeff Grampp with Alliance Global Partners. Please go ahead.

Jeffrey Grampp: Hey guys. Paul, I wanted to hit on the kind of exploration or organic growth prospects that you guys talked about with finding new inventory. What’s kind of the comfort level in having that be a decent chunk of the capital program? I don’t know if maybe taking Q4 as a proxy is a good example, like of the dozen or so wells you guys are going to drill in Q4, how many would you say are those kind of testing delineation type wells versus development wells? Or any kind of parameters you can put around how much capital is going to work in that bucket, if you will?

Paul McKinney: Yes. Okay. That’s a very good question, Jeff. And I’ve always said that we got to walk before we can run. If you look at all of the challenges facing Ring Energy, we keep pointing to what we believe is our number one issue. And our number one issue is to reduce debt and strengthen the balance sheet. And so — and I’ve been really laser-focused on making sure that we allocate capital to the projects that actually maximize free cash flow generation. So everything is focused on capital efficiency here. So we really cannot afford to put capital investments into high-risk investment opportunities. We just can’t do that. However, this year, we have performed very well versus our forecast and our goals. And so we saw several opportunities to expand our inventory organically.

And again, thanks to our outstanding geoscience team, they had identified some of these opportunities, and we’ve also seen what other operators have done up and down in the Central Basin Platform. And so we decided to try some of these ideas on our own leases. So this quarter, we’re actually drilling four wells that — and that represents, what, about 25% of our capital this quarter, I believe, or maybe a little bit more, a pretty good number. And so we believe that we have the opportunity to take a little bit more risk on some of these wells, and we’ll see how that goes. But the benefit for taking these risks right now could lead to an enormous number of eventual PUD locations that could end up hitting our books. And so now going off in the future, again, I am more focused on debt reduction than I am about trying to grow the company, okay?

And so the balance sheet is the most important thing. I mean, there’s three rules in the oil and gas industry, three things you need to remember is balance sheet, balance sheet, balance sheet, right? And so we’re going to be laser-focused on that. And so going off into 2025, you will see that we will be sprinkling in some of these higher-risk opportunities. But we’re going to balance those higher-risk opportunities with our goals on debt reduction, the goals that we have set for ourselves for production and maintaining and slightly growing our production, and also the need to continue to replace inventory and build inventory. And so it’s a tight rope. And I say we got to walk before we run. As our leverage ratio gets down below 1, then you’ll see that we’ll start spending a little bit more towards inventory growth.

And then depending on product prices and the health in the company and whether we’re paying some kind of — or generate some kind of a real capital return to our shareholders or the size and scale necessary to do that, all those things kind of come into play. But you’ll see that as we grow and get healthier, you’ll see that we’ll allocate more of our capital dollars towards building inventory and for growth. Does that answer your question, Jeff?

Jeffrey Grampp: Got it. Yes. Really helpful. Thanks, Paul. And following up on that, is it fair — since these test wells are generally within your existing footprint or fairly proximal, I assume, is it fair to say to the extent you have success and find some new areas of development that the incremental investments on the infrastructure facility side would be fairly modest, if anything, given that you’re kind of within your existing fairways. Is that a fair conclusion?

Paul McKinney: It is in most, but not in all, okay? And so I’m going to turn that over to Shawn Young because he’s very intimately involved and knowledgeable about our infrastructure. So Shawn, jump into that.

Shawn Young: Yes. For the most part, I think your quote is accurate in that the production facilities and stuff are proximal and where we’re drilling these wells, we’ll be able to take advantage of that. But there is some water infrastructure cost, both on the water supply side and also on the water disposal side that we will have to invest some dollars there to keep up with some of the expected rates.

Jeffrey Grampp: Got it. Understood. Look forward [indiscernible]. Thanks.

Operator: Thank you. And our next question comes from John White at ROTH Capital. Please go ahead.

John White: Good morning. Good afternoon. My questions have been answered. I’ll turn it back to the operator.

Operator: And our next question comes from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Paul or Alex, oil was about 66% of third quarter production. So you had good gas production growth. Oil, I think, was slightly lower than the second quarter. Are there infrastructure issues or constraints that are impacting the production mix in the third quarter and also in the fourth?

Paul McKinney: No. I don’t know if you have a different opinion, Alex.

Alexander Dyes: No. And I think what you’re alluding to is why did our oil mix go down, and it’s more that in the second half of ’24, we — there was a plant expansion in one of our major fields. And so they’ve expanded the plant, lowered the back pressure on all the pipeline. And so we’re able to get more gas sales there as well as some in the CBP. I’d like to defer to Shawn to give you a little bit more input on that, but that’s what that is.

Shawn Young: Yes, there’s really — there’s three things kind of driving that. The one that Alex alluded to was a plant expansion that did lower our line pressures. In the CBP area, we also had increased run-time due to the midstream entity there. And so that basically allowed us to sell our gas. And then the third thing is we have been doing some facility upgrades in some of the different areas that have also improved the ability to deliver gas. So all of those combined have kind of increased our overall gas sales and takeaway for the third quarter.

Jeff Robertson: Is there a — when you do that, is there — since I think third quarter — since gas prices have been negative, is there an oil production benefit that comes with the ability to increase oil or, I’m sorry, natural gas takeaway?

Shawn Young: In some of that, there is, especially on the plant expansion where actual line pressures are reduced. And so yes, we are seeing a little bit of a benefit, obviously, by reducing our operating pressures there, we’re getting some incremental oil as well.

Paul McKinney: Yes. And don’t forget, not all of our gas is as negative as across the board. So in the South, we tend to get a better price for our product. In the North, we tend to get a worse price.

Jeff Robertson: Paul, if the goal to allocate capital to generate the most amount of free cash flow would suggest you’re going to preferentially allocate to where you’ve gotten the highest concentration of oil on the asset base, do you think the oil production mix changes much in 2025 from where it is in the second half of ’24?

Paul McKinney: No, I don’t actually. Now it could occur, because I will say that — let’s just go back to Ector County, for example, the wells that we’ve been drilling there have really one of the highest oil weightings in our portfolio. And so we are currently working on our budget for next year, and we’re looking at the inventory and opportunities and Ector County is going to be playing a large part. So it’s all going to be a function of the allocation mix. But again, we will be focusing on increasing our oil mix. And so it depends on some of the wells that we test here this quarter right now, how that impacts and how those come in and what are the oil, what’s the oil mix from those investments and that kind of thing. But yes, that’s a continuous thing we’re doing. Everything we look at is — everything we do from operating the existing assets to allocating capital to the new wells we drill, everything is focused on maximizing free cash flow generation.

Jeff Robertson: When you get the balance sheet to the point you want in terms of leverage ratio, just based on the valuation slide you showed, you’ve talked in the past about a dividend, but where would a share repurchase plan or share repurchase fit in your hierarchy of uses of free cash?

Paul McKinney: Well, I mean, to me, I look at capital returns to my shareholders. When I refer to that, I’m referring to all those alternatives. In other words, so it’s going to be a function of what’s the best opportunity — investment opportunity for our shareholders when we look at that. Is it better to be — to return a dividend to our shareholders, or would it be better to do a stock buyback? And that’s going to be a function of where our stock price is versus what we think the intrinsic value is and all of that. So I can’t really tell you exactly where it will go, but it is always part of the conversation and always will be because, again, if we choose — now of course, if we do ever choose to put in a dividend, that kind of goes back to being of a certain size and scale so that we know and have confidence that we can sustainably deliver that dividend.

We never want to put something like that in place and not be able to deliver it sometime down the road. And so I think that answers your question.

Jeff Robertson: It does. And lastly, we’ve talked in the past about scaling the company and the growth through acquisition strategy. Given where you are today, do you still have a preference for heavier PDP-type assets to — because you get the collateral value to fit on to the right side of the balance sheet to go along with the production and cash flow?

Paul McKinney: We do. But again, it’s also a function of what you acquire and how you acquire it, right? And so we are looking for certain types of assets. And we’ve talked about this in the past, Jeff. We talked about the fact that we like these long-life, shallow decline wells, predominantly oil and liquids, oil because you end up generally having much higher margins, higher operating margins. And so all of these things come together. And then so a PDP buy that just comes as PDP, well, we’re going to have to buy that at a pretty high discount rate. But if it comes with undeveloped opportunities with it that are similar in economics or competitive with the inventory that we already have, well, that’s kind of the holy grail that we’re looking for.

Everything we try to achieve is a balance of both. We’d like to grow it through PDP buys, but it’s actually a lot better if you can also supplement that with an inventory of undeveloped opportunities that are competitively priced and economic with what we already have.

Jeff Robertson: Thank you.

Paul McKinney: You bet.

Operator: Thank you. [Operator Instructions]. Our next question comes from Noel Parks at Tuohy Brothers. Please go ahead.

Noel Parks: Hi, good morning. Just touching back on what your geoscience folks are working on with the drilling you’re going to be doing. Just, is — I guess I’m wondering, I’ve had the impression that there’s long been a realization that there are other formations that can be targeted beyond the San Andres. And I was wondering, is that sort of what you’re looking to explore? My impression also has been that those other targets are sort of highly variable as far as where they’re productive? Or are you looking more I guess maybe more precise location of your regular targets, and that’s the work they’re trying to do?

Paul McKinney: Yes. So right now, and I’ll kind of let the cat out of the bag here, so to speak, we believe that in the Central Basin Platform, in these areas where we’ve been drilling these stack and frac verticals that there’s opportunity in several areas that we haven’t been drilling in the past to apply either that technology or horizontal technology. And so with these multiple stacked pays depending on the thickness, the resources in place. And so taking these new technologies and applying them in areas that we haven’t done in the past, allows us to expand that inventory, okay? And so we’ve — in some areas, we’ve proven that in an area that has been down spaced to 40 or 20-acre spacing, we found that it’s much more cost-effective to drill these really inexpensive vertical wells, apply modern technologies to complete them.

So you — per frac and plug your way out of the hole, you drill it all out and you bring it all on. That’s been very effective, very efficient and very economic. But we’re also seeing that horizontals in some of these thicker individual pay zones also recover large EURs and have great economics. And so we’re trying to expand all that out. So I think that answers your question, Noel. But the bottom line is in the Central Basin Platform, in the stacked pay areas, the industry is learning more and more now, whereas four, five, six, eight, 10 years ago when people tried the same technology, back then the technologies weren’t as mature. So today, we’re able to make some of these other ideas that people have tried years ago. They are now becoming more economic and becoming economic as a result of the technologies associated with how we actually drill and complete the wells.

Noel Parks: Got it. Thanks. And actually, just speaking of returns, looking at your more sort of bread-and-butter development. Can you sort of catch us up on what RORs look like when we’re talking, say, even like a realized $60 oil price just because, again, I don’t know how much awareness there is that the breakevens are considerably more generous than they are with unconventional plays?

Paul McKinney: Yes. So we do benefit. That’s part of why Ring Energy and other companies that look a lot like us can generate the types of returns that we do is because the breakeven costs are low. If you remember, when I first came here four years ago, our breakeven costs then were right around that $25 mark. But we’ve also seen a considerable amount of inflation since that time period. So our breakeven costs on drilling our wells is really around that $30 to $35 value. And — but when you consider current oil price, that’s still a lot. But you got to remember, we also carry the full G&A of the company. We have interest expense, paying down our debt. We have all these other different things. And so that’s why we’ve been saying that although we are still slightly growing our production at the current oil prices.

If oil prices fall appreciably lower than where they’ve been here in the last little while, our preference is to pay down debt, so we will pull back on that capital spending for growth, or — and so we’ll pull capital spending levels down to maintenance levels and then in preference of paying down debt. And so that’s kind of how I look at the future. That’s how I look at the economics out here. And so we’re just looking for — and part of the strategy at this point in the development of Ring and this management team is to get to the point where we have more ways to win. We’ve proven that we know how to acquire properties effectively and generate a profit, integrate them into our operations, and continue generating returns. And we’ve also been able to continue to increase the inventory of undeveloped opportunities.

By taking this next step of organically identifying locations on and beyond our own acreage will give us another way to win to build that inventory so we can sustainably deliver these types of returns.

Noel Parks: Terrific. And just one other thing I was wondering about, with the sales of those non-core assets that you’ve done, just curious what vintage of leasing or acquisition were those? Just how long had those been in the portfolio?

Paul McKinney: Well, they were part of — when Ring was first formed back in 2013, these were some of the very first assets they acquired, and they are in what we call the northern portion of our Central Basin Platform. They were vertical wells that were there before they started horizontal developments. And so they are older vintage wells, very steady declines. But on a per-barrel basis, their operating costs were among the higher end of our inventory. And so there was an operator out there that expressed interest, and they were among the higher operating costs, and we negotiated what we think is a very favorable deal on that. And so it’s really in the best interest of our shareholders. We do a couple of things. Number one, we’re able to pay down additional debt as a result of that transaction.

At the same time, it also helps improve our operating costs on a per-barrel basis, and it reduces them. So yes, I think it’s a really good deal overall. It’s in a more mature area in the northern part of our Central Basin Platform. And they were just non-strategic to us and non-core.

Noel Parks: Great. Thanks a lot.

Paul McKinney: Thank you. Noel.

Operator: And our next question is a follow-up from Jeff Robertson of Water Tower Research. Please go ahead.

Jeff Robertson: You just addressed part of it, but my question was around the non-core asset sale. Do you — are there many other assets that you would consider non-core that if the right structure came along, you’d consider selling?

Paul McKinney: Yes. We’re pretty tight now. We’ve done a good job scouring the — I’m not saying that we don’t have anything that we wouldn’t sell. But for the most part, we’ve cleaned up our portfolio. And yes, the numbers are rocking right now. I mean, I really like what the operating team is doing with these, everything associated with capturing every last molecule of methane and getting it to market to building first-class facilities and tightening up our operating costs. We’re making a lot of headway in terms of reducing our failure frequencies, and we’re doing all kinds of things right now to reduce operating costs out in the field. We’re very mindful of the cost in the office. Our total operating cost is just something we focus on, and we’re incentivized to focus on here at Ring Energy, and we know it’s in the best interest of the shareholders, and so…

Jeff Robertson: Thank you.

Operator: Thank you. And this concludes our question-and-answer session. I’d like to turn the call back over to Paul McKinney for any closing remarks.

Paul McKinney: Well, thank you, Rocco. And on behalf of the entire team and the Board of Directors, I want to once again thank you for listening and participating in today’s call. We are pleased to have posted solid operational and financial results to date for 2024. And our outlook for the remainder of the fourth quarter and into next year remains strong. We will continue to keep you and everyone appraised of our progress, and thank you, again, for your interest in Ring Energy. I hope everybody has a great day.

Operator: Thank you. This concludes today’s conference call. We thank you all, for attending today’s presentation. You may now disconnect your lines, and have a wonderful day.