Good day and welcome to the Ring Energy Third Quarter 2024 Earnings Conference Call. All participants will be in listen-only mode. 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.

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.

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 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 in 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 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 in 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. The 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 in 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 were 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 sale 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 the 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.

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 a 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 paydown 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 a 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 was $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 were $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 at 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.

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%, which 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-month 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.

Thank you. We will now begin the question-and-answer session. Today's first question comes from Neal Dingmann at Truist. Please go ahead.

Good morning. Paul, I'd like to follow up on what you mentioned earlier, specifically regarding inventory. Can you provide an idea, perhaps in years, of what the current inventory looks like? Additionally, as you consider both vertical and horizontal opportunities, has that changed the inventory situation? I'm trying to understand how the potential has shifted due to drilling these types of wells.

Yes, that's a great question, Neal. According to our corporate deck, we estimate that we have about 450 opportunities in our inventory. To be frank, we don’t have the 10 to 15 years of running room that many larger companies in the Delaware and Midland Basin possess. This is part of why we're focused on acquisitions. As I mentioned in the release and on this call, we are entering a new phase of development. We have expanded our geoscience and engineering team to begin organically identifying opportunities to add to our inventory. I believe some of the capital we are investing this quarter may support that effort. You can expect to see two main strategies for building and expanding our inventory — through acquisitions and organic growth. Currently, we have our short and medium term plans well in hand, but we lack the 10-year outlook that others have. This is why we are concentrating on expanding our options moving forward. Did that address your question, Neal?

Yes, exactly. Lastly, I would like to know how you perceive opportunities, both existing and potential, in relation to the platform and the shelf. Are you viewing them similarly now, or are there differences? How do the economics compare?

Yes, I'll let everyone share their thoughts on that. I believe the economics have improved this year due to a decrease in capital costs for goods and services. This has led to a slight reduction in the costs associated with drilling and completing our wells, resulting in better economics if oil prices remain constant. However, the recent volatility introduces uncertainty regarding the oil prices that will enable us to recover our investments. Nonetheless, the economics will depend on oil prices. I also anticipate an increase in activity levels in the Permian Basin in the future, which could diminish some of our current savings depending on future activity. Regarding inventory and available opportunities, this summer marked the beginning of disposals from larger companies, and I expect to see more dispositions aligning with our strategy. This will present us with additional opportunities. I'm optimistic about our future regarding inventory and economics. We have clearly shown our ability to drill and complete wells efficiently while delivering strong returns for our shareholders. Alex, would you like to add anything?

Yes, thanks, Paul. Neal, we have a slide in the IR deck on Page 27 that supports the point Paul mentioned. In drilling and completions, our cost structure has decreased. The question we often receive is about investments in vertical versus horizontal operations. As we have reduced our costs in both areas, they have become more stable. We are continuing to focus on fundamental improvements and adding inventory through acreage expansions or acquisitions, and we anticipate ongoing opportunities to negotiate individual deals with other operators. Did that address your question, Neal?

Yes, thanks guys.

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?

That's a great question, Jeff. I've always said that we need to walk before we can run. Considering the challenges facing Ring Energy, our top priority is to reduce debt and strengthen the balance sheet. I have been very focused on ensuring that we allocate capital to projects that will maximize free cash flow generation. Therefore, we cannot afford to invest in high-risk opportunities at this time. However, we have performed well against our forecast and goals this year, which has allowed us to explore several opportunities for organic inventory expansion. Our talented geoscience team has identified these opportunities, and we have also observed what other operators have been doing in the Central Basin Platform. As a result, we are drilling four wells this quarter, which constitutes about 25% of our capital for this quarter. We believe we can take on a bit more risk with these wells, and the potential outcome could lead to a significant number of future proved undeveloped locations. Moving forward, my primary focus remains on debt reduction rather than company growth. The balance sheet is our most crucial concern. In the oil and gas industry, it boils down to balance sheet, balance sheet, balance sheet. We will continue to prioritize this. As we head into 2025, you'll see us start to incorporate some higher-risk opportunities while still balancing our debt reduction goals, our production targets, and the need to replace and build inventory. It’s a balancing act. As our leverage ratio decreases below 1, we will start allocating more resources toward inventory growth. Depending on product prices, the company's overall health, and our ability to generate real capital returns for our shareholders, many factors will influence our decisions. But as we grow stronger, we will direct more of our capital towards building inventory and pursuing growth. Does that address your question, Jeff?

Got it. Yes, that's really helpful. Thanks, Paul. Following up on that, since these test wells are generally within your existing footprint or fairly close by, is it reasonable to say that if you find success and discover new areas for development, the additional investments in infrastructure would be relatively modest, considering you're operating within your current areas? Is that a fair conclusion?

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.

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.

Got it. Understood. Look forward to more detail.

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

Good morning. Good afternoon. My questions have been answered. I'll turn it back to the operator.

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

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?

No. I don't know if you have a different opinion, Alex.

No. What you're referring to is the decline in our oil mix, which is primarily due to a plant expansion in one of our major fields in the second half of '24. The expansion has reduced the back pressure on the pipeline, allowing us to increase gas sales both there and in the CBP. I’d like to let Shawn provide you with more details on that, but that’s the situation.

There are three main factors contributing to that. One factor is the plant expansion mentioned by Alex, which reduced our line pressures. In the CBP area, we also experienced increased run-time due to the midstream operations there, allowing us to sell more gas. The third factor is that we have implemented facility upgrades in various areas, which improved our gas delivery capabilities. Together, these factors have boosted our overall gas sales and takeaway for the third quarter.

Is there an oil production benefit that comes with the ability to increase natural gas takeaway, especially since gas prices have been negative in the third quarter?

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.

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.

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?

No, I don't actually. It could happen, as the wells we've been drilling in Ector County have one of the highest oil weightings in our portfolio. We are currently working on our budget for next year, examining our inventory and opportunities, with Ector County playing a significant role. The allocation mix will be a key factor. Our focus will be on increasing our oil mix, which will depend on the results of some wells we are testing this quarter and how they perform in terms of oil mix from those investments. This is an ongoing effort for us. Every aspect of our operations, from managing existing assets to allocating capital for new wells, is aimed at maximizing free cash flow generation.

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?

I look at returns to my shareholders in terms of all available options. The decision will depend on the best opportunity for our shareholders, whether that’s paying a dividend or conducting a stock buyback. This will be influenced by our stock price compared to what we believe the intrinsic value is. While I can’t predict exactly where this will lead, it will always be part of our discussions. If we do decide to introduce a dividend, we must ensure it is of an appropriate size and scale to maintain confidence in our ability to deliver it sustainably over time. We want to avoid committing to something we may not be able to uphold in the future. I hope that addresses your question.

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 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?

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.

Thank you.

You bet.

Thank you. Our next question comes from Noel Parks at Tuohy Brothers. Please go ahead.

Hi, good morning. I wanted to follow up on what your geoscience team is working on regarding the upcoming drilling. I've had the impression that there has long been an understanding that there are other formations to target beyond the San Andres. Is that what you are planning to explore? Additionally, I have the impression that these other targets can vary significantly in their productivity. Are you focusing more on identifying precise locations for your regular targets, and is that what your team is working on?

Yes. Currently, we believe that in the Central Basin Platform, there are opportunities in areas where we haven't previously drilled, particularly regarding stacked and frac vertical wells. By applying new technologies, including horizontal drilling, in these previously unexplored areas, we can expand our inventory. We've seen that in some locations with tight spacing, it’s more cost-effective to drill inexpensive vertical wells and utilize modern completion techniques. This has proven to be efficient and economical. Additionally, we have observed that horizontal drilling in some of the thicker pay zones can also yield substantial estimated ultimate recoveries and favorable economics. Overall, in the Central Basin Platform's stacked pay areas, the industry is gaining more insights now, unlike several years ago when similar technologies were less developed. As a result, innovative ideas that were previously tested are becoming more economically viable today due to advancements in our drilling and completion methods.

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?

Yes. We benefit from having low breakeven costs, which is part of why Ring Energy and similar companies can achieve strong returns. When I joined four years ago, our breakeven costs were about $25. However, inflation has increased those costs, and now they range between $30 and $35 for drilling our wells. Despite that, current oil prices still allow for profitability. It's important to consider that we also have general and administrative expenses and interest expenses related to our debt. That's why, despite slightly increasing our production at current oil prices, if prices drop significantly, we would prefer to focus on paying down debt. This would involve reducing capital spending to maintenance levels rather than pursuing growth. Looking ahead, our strategy as a management team is to create more opportunities for success. We’ve shown that we can acquire properties effectively and integrate them into our operations for profit, while also increasing our inventory of undeveloped opportunities. By identifying new locations both within and beyond our current acreage, we aim to build our inventory and sustainably deliver strong returns.

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?

They were part of the assets acquired when Ring was first established in 2013, located in the northern area of our Central Basin Platform. These were vertical wells that existed prior to the start of horizontal development and are older vintage wells with steady declines. However, their operating costs were on the higher end compared to our inventory. An interested operator came forward, and after negotiations, we reached what we consider to be a very favorable deal. This transaction is in the best interest of our shareholders for a couple of reasons. First, it allows us to pay down additional debt. Second, it helps to lower our operating costs on a per-barrel basis. Overall, I believe this is a positive deal. The area is more mature in the northern section of our Central Basin Platform, and these assets were non-strategic and non-core for us.

Great. Thanks a lot.

Thank you, Noel.

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

You mentioned part of it, but my question was about the sale of non-core assets. Are there other assets you would consider non-core that you might sell if the right opportunity arose?

Yes, we're currently in a strong position. We've done a good job evaluating our portfolio, and while we're not completely averse to selling certain items, we've mostly refined what we have. The performance is impressive right now. I'm really pleased with what the operating team is achieving in terms of capturing every last molecule of methane, bringing it to market, constructing top-notch facilities, and managing our operating costs efficiently. We're making significant progress in lowering our failure rates and implementing various measures to reduce operational expenses in the field. We're also very conscious of costs in the office. Our overall operating costs are a primary focus for us at Ring Energy, and we understand that prioritizing this is in the best interest of our shareholders.

Thank you.

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.

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.

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.