Good morning, and welcome to Earthstone Energy's Conference Call. At this time, all participants are on a listen-only mode. A brief question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference call is being recorded. Joining us today from Earthstone are Rob Anderson, President and Chief Executive Officer, Mark Lumpkin, Executive Vice President and Chief Financial Officer, Steve Collins, Executive Vice President and Chief Operating Officer, Scott Thelander, Vice President of Finance, and Clay Jeansonne, Director of Investor Relations. Mr. Jeansonne, you may begin. Thank you, and welcome to our Q3 2022 Conference Call. Before we get started, I'd like to remind you that today's call will contain forward-looking statements within the meaning of federal securities law. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in our annual report on Form 10-K for the year ended December 31, 2021, the Q3 of 2022 earnings announcement, and in our Form 10-Q for the Q3 that we filed yesterday. These documents can be found in the Investors section of the website, www.earthstoneenergy.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 issued yesterday. Also, please note information recorded on this call speaks only as of today, November third, 2022. Therefore, any time sensitive information may no longer be accurate at the time of any replay listening or transcript reading. Today's call will begin with comments from Robert Anderson, our President and CEO, followed by remarks from Steve Collins, our COO, and Mark Lumpkin, our CFO. We'll have some closing comments from Robert. I'll now turn the call over to Robert. Yeah, thanks, Clay. Most of you know Clay, he joined us a few months ago. I'm glad to have him here. Good morning to everyone on the call today. Thank you for taking the time to join the call or listen on the web. I'm a little bit hoarse, and I'm sure it's because of our Astros and we've got one more good game left out of town tonight. Let's get started. I'm very proud of how we have transformed Earthstone in such a short timeframe, and we continue to see the benefits from the seven acquisitions we have closed in the last seven quarters. Our targeted consolidation efforts have materially repositioned the company and provided our shareholders with an investment in an entity that has a substantial operating footprint in the Permian Basin. I'm incredibly proud of our team, and I wanna thank our existing and recently added workforce for their outstanding hard work and dedication, which enabled us to report the strong Q3 financial and operational performance we announced yesterday. This includes record production levels that exceeded the top end of our guidance range by approximately 5%, as well as record-setting levels of adjusted net income, Adjusted EBITDAX and free cash flow. I'm pleased to report that we reached over 100,000 BOE per day in September. Our overall outperformance for the Q3 was primarily driven by the continued success of our development program, which highlights the quality inventory from all the acquisitions, along with our inventory from our existing asset base. The strength of this large, low declining asset base also assisted in our outperformance. Steve will discuss our targeted cost synergy initiatives and recent well results in greater detail in a bit. When you have 14 of 19 wells brought online in the quarter with oil rates above 1,000 BOE per day, it sure highlights the asset quality we have accumulated. As you'll recall, we closed the Titus acquisition on August 10 with assets in the northern Delaware Basin, including the state line trend area of New Mexico and Texas. I'm particularly pleased with this immediately accretive acquisition, and while we are continuing the integration of these assets, they contributed to the company's results this quarter. We remain committed to capital discipline and the continued strengthening of our balance sheet, and we delivered on those commitments. During the quarter, we generated over $174 million of free cash flow. Year to date, we have generated over $374 million of free cash flow. You will recall that this includes 3 acquisitions this year, which closed in February, April and August, so only a partial year for all these acquisitions. Our continued generation of substantial free cash flow resulted in the paydown of a significant amount of debt, which Mark will address here shortly, and allowed us to deliver on our promise of strengthening our balance sheet by achieving a leverage ratio of about 0.8x at the end of the quarter when using Q3 annualized Adjusted EBITDAX. In early October, we were presented with a unique opportunity to repurchase a portion of Warburg Pincus ownership position in the company. We proactively repurchased 3 million shares of Class A Common Stock at a discount to the closing price. The repurchased shares have reduced our total outstanding share count by 2%. We view this as a highly accretive, opportunistic use of free cash flow, while at the same time not decreasing our growing trading liquidity. The strength of our balance sheet remains the top priority for Earthstone. In support of that effort, we will continue to focus on investing our substantial free cash flow generation in reducing our debt, as well as evaluating other opportunities that provide the optimal return for our shareholders. We expect to have a better view of how these options will play out as we move into 2023. We are leveraging our expanded position to drive down overall corporate operating and development costs, and we will continue to execute our deliberate asset consolidation strategy as appropriate. To be clear, we are not interested in simply growing scale. Our efforts have been and will continue to remain focused on profitable growth that benefits our shareholders. In short, our consolidation strategy is focused on, one, strategically expanding our operational footprint. Two, increasing our inventory of high rate of return drilling locations. Three, and perhaps most importantly, continuing to build upon the foundation we have created with our growth to date in sustainable free cash flow, which will benefit all of our shareholders. Now I'll turn the call over to Steve Collins to provide an update. Thanks, Robert. Good morning, everyone. The Q3 was another outstanding quarter for the operations group, and I want to thank all of them for their tireless efforts as we continue to execute on opportunities to reduce costs on our expanded operational footprint and the drilling of high rate of return wells. We continue to be very active in the Q3, running two drilling rigs in the Midland and Northern Delaware Basins. We recently added an additional Delaware Basin rig that will focus on our newly acquired Chisholm and Titus assets. Its first activity will be focused on the Dark Canyon pad in Eddy County. In addition, we also have frack operations underway in both the Midland and the Delaware Basins. The team spudded 18 wells in the Q3 and completed 19 wells. Our focused acquisition strategy has assembled a high-quality asset base with a deep inventory of very economic derisked future drilling locations. As Robert mentioned during the quarter, our operations team brought online some great wells, which have met or in many cases exceeded our expectations, helped us reach record levels of production for Earthstone. We have shown the areas of results on page 8 of our updated corporate presentation, which is available on our website. In addition to the Delaware Basin, on our recently acquired acreage from Titus, we completed six wells in Lea County, New Mexico, near the state line. The Cattleman Lonesome Dove wells began producing in early September and targeted the first and second Bone Springs. The six wells, which are 7,700-foot laterals, had an average 30-day IP rate of over 1,520 BOE per day per well, with over a 73% oil cut. We expect these wells to have an average payout of less than six months. Also, in the Northern Delaware Basin on our Chisholm acreage we acquired earlier this year, we completed six additional wells on four separate pads. I'll highlight a couple of those. We brought on four wells during the quarter in Eddy County, New Mexico. The two-well Cletus pad targeting the Wolfcamp A had an average IP 30 rate of 1,370 BOE per day. Both wells had laterals of 9,750 feet and an oil cut of around 70%. In early September, we turned two. We turned to sell two wells in the Salt Draw pad, which had an average IP30 of over 1,570 BOE per day through laterals of 4,700 feet and an oil cut of approximately 77%. Both wells targeted the second Bone Spring interval. Finally, in the Midland Basin, I'd like to highlight the Barnhart pad in Irion County, Texas. This five-well pad was developed on the acreage we acquired from Tracker in July of 2021. These wells were drilled with a lateral length of approximately 10,000 feet. We have been pleased with the results from these five wells. The pad began producing in mid-August with an average IP30 rate of 1,170 BOE per day and is 81% oil. On average, the drilling and completion cost for each well was only $8 million. Given the production rate and low-cost nature of these wells, we expect them to pay out in just over a year. We've identified over 40 future locations in this area and will continue to allocate a portion of our capital program to this area. As in the past, we will continue to be laser-focused on reducing costs on our recently acquired assets as well as across our existing asset base. We recognize LOE for the quarter was higher than expected. This is due to several items, including increased workover activity, gathering and processing charges, and increased inflationary pressures. The workover program has additional benefits long term as we repair and return wells to production that were offline or needed work at the time of the acquisitions. The goal is to reduce failure rates and increase runtimes by optimizing lift methods and improving mechanical designs. We estimate we have spent a little over $7 million over the last two quarters on workover projects, returning approximately 6,000 BOE per day to production. Given our low-cost mindset, we will continue to increase operational synergies with personnel and systems to lower overall LOE per BOE. When we put together our guidance in July, we expected to see inflation from Q3 into Q4 in the range of 5% on the D&C side. That estimate has held true. The rate of inflation change certainly has decreased relative to what we were seeing in the first half of the year, but inflation is still a factor. With that, I'll turn it over to Mark. Thank you, Steve. Similar to in the past, I will focus my comments today on providing additional details on some meaningful metrics and key highlights. As you know, a detailed breakdown of our results is available in our earnings release and in our 10-Q. First, starting with the balance sheet and the credit facility in particular, the elected commitments under our credit facility were increased from $800 million to $1.2 billion in August in conjunction with the closing of the Titus acquisition. Alongside the increase in commitments, the borrowing base at that time increased by more than 20% to $1.7 billion. Subsequently, our normal course borrowing base redetermination was conducted in September, and the borrowing base was increased further from $1.7 billion to $1.85 billion. I'd really like to thank our banks for their commitment and continued support of Earthstone, with the significant increase in our borrowing base being indicative of the high quality of our increased asset base. Now let me turn to financial results for the quarter. Net income for the Q3 was $299 million or $2.09 per adjusted diluted share. Our adjusted net income per share was $1.30, and adjusted EBITDAX was $346 million, which was 15% higher quarter-over-quarter. Q3 adjusted net income and adjusted EBITDAX were both records for the company and were driven by the incremental production from a full quarter of Bighorn assets and a partial quarter of Titus assets, complemented by commodity prices that remain very strong despite being down from the peak oil prices we saw in the Q2. Free cash flow for the quarter was approximately $175 million, which was a 7% increase from the Q2. For the nine months ended September 30, we generated a free cash flow of $374 million, which was also a record for the company. We have continued to utilize free cash flow to repay credit facility debt. During the quarter, adjusting for the Titus acquisition, we paid down over $290 million in debt on the credit facility. On September 30, 2022, we had approximately $636 million drawn on the credit facility in total debt of just under $1.2 billion. Our debt to annualized EBITDAX ratio for the Q3 was 0.8 times, which is ahead of our plan. We plan to continue to use free cash flow to reduce debt and fully expect to remain below 1 times debt to adjusted EBITDA going forward. From a production standpoint, we're pleased to surpass the high end of our Q3 guidance range by approximately 5%, with company record production of 94,329 barrels of oil equivalent per day, which was comprised of 41% oil, 32% natural gas, and 27% natural gas liquids. Given the recent strong results from our drilling program, we are raising our Q4 guidance by about 2%, with production expected to range from 98,000 to 102,000 barrels of oil equivalent per day. Turning to the capital expenditures, we spent $147 million in the Q3, which was a little bit lower than our prior Q3 expectations. For the Q4, we expect capital to range from $170 million-$185 million. This is an increase of a little over $10 million at the midpoint for the second half of the year compared to our prior guidance in August for the second half of the year CapEx. This is largely driven by our ability to extend the completed lateral length of wells drilled in the Q4 by about 30% compared to our prior plan and our guidance, which is really resulting in significantly improved capital efficiency with the longer laterals. To a lesser degree, we also expect higher non-op capital activity levels in the Q4. As Steve mentioned, our operating expense was higher than expected for several reasons, with LOE per BOE coming in at $8.74 for the quarter, which was about $1 per BOE above the midpoint of our guidance. This was driven in approximately equal parts by workover activity on the recently acquired assets, by inflationary pressures, and by renegotiated gas processing agreements. On the gas processing side, which we do include in our LOE, the increase is largely a function of contracts that were renegotiated or recut to move from percent of proceeds to fee-based agreements. This increases LOE, but it's more than offset by incremental increases in revenue. It's just that this flows through our LOE. So the net benefit is very positive, but it does increase LOE. We do expect LOE to be moderately lower in the Q4, and we are guiding to a range of $8 to $8.50 per BOE. On the commodity hedging front, we're currently hedged for the Q4 at around 54% for oil and 62% for gas. For 2023, based on the midpoint of Q4 guidance, we're hedged about 35% oil and about 31% for gas. I would note that we've continued to enter into a mix of hedging structures that provide downside protection, but also provide upside exposure with our 2023 oil book being approximately equally split between swaps, collars, and puts, and our gas book largely utilizing relatively wide collars. You can find our updated hedge position in the earnings presentation we posted to the website. Additionally, I'd like to highlight that we are heavily hedged on Waha basis going forward, with hedges in place for 2023 that covers about 75% of our total gas, and really close to 100% of our Waha pricing exposed gas as we do have a bit of gas that is exposed to Houston Ship Channel versus to Waha. We've got a good percentage of 2024 hedged for Waha basis as well. Finally, I'd like to highlight the significant increase in our current trading liquidity. For the Q3, trading volumes averaged 1.8 million shares per day or $24 million of value traded per day, which is an increase of about 8% over the Q2. We believe this added trade liquidity will benefit existing and future shareholders, and we're really pleased to see the improvements in the trade liquidity. With that, I'll turn it back over to Robert for closing comments. Thanks, Mark. Looking ahead a bit, we will continue to deploy our substantial cash flow into opportunities that we believe will provide the best options to create long-term shareholder value for Earthstone. Those options include reducing the outstanding debt on our credit facility, acquiring additional complementary assets that fit our stringent criteria, while at the same time allowing us to maintain our strong balance sheet, continue to execute our expanded high rate of return drilling program, which will add production organically, and finally, executing on potential future shareholder return initiatives. As we continue to evaluate these available options, our near-term focus is to use free cash flow to reduce borrowings on our credit facility. In closing, in less than two years, we have transformed Earthstone into a leading E&P with a stable production base of approximately 100,000 BOE per day that provides a more diverse product mix, a low-cost operating structure, and a deep inventory of high return future drilling locations that further support our efforts to maintain, but perhaps a bit grow production over the long term. In summary, we believe we've built a company that offers an attractive value proposition to investors, including having one of the highest free cash flow yields at one of the lowest enterprise values to EBITDA multiples in the E&P sector, and a current valuation that is significantly below our proved developed reserves value. Of course, none of this would have been possible without our best-in-class workforce's constant dedication and hard work. As important has been the continued commitment and support of our shareholders. With that, operator, I'd like to turn the call back to you to take some questions. Thank you. Ladies and gentlemen, at this time, we will be conducting a question-and-answer session. If you'd like to ask a question, you may press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing this, the star key. Our first question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question. Good afternoon, Robert, to you and your team there. Hey, thanks, Charles. Robert, it was good to see those Delaware Basin results on your two most recent acquisitions there. I wondered if you could talk about, and I think you addressed this a bit in your prepared comments, how those wells performed versus your acquisition case. Second, what the opportunities are going forward to further improve those well results. It seems like the most obvious avenue to do that might be longer laterals, but that's probably not the only one. If you could just talk about those two aspects. Yeah. We really like the results. As Steve mentioned, it kinda in some cases met our kinda acquisition cases. In a couple of cases, maybe we were a little bit higher on the actual results compared to our type curves, which is always nice to see. We're pretty conservative on the way we value assets, so that's kinda lined up with the way the outcome of these wells are. Probably it's, you know, a few trades happen that allow us to do longer laterals, which is super important, but more importantly is just controlling your destiny. We're working on some trades where we'll actually have control of when we can go drill wells. I would expect that all our wells look this good in the future, but you know, depending on where we're drilling and what horizon, and as we co-develop different horizons together, you know, they're not all gonna be exactly the same, but we're really pleased with the results we've seen so far, and we probably have some more coming up. Got it. Just sticking on the theme of well results, you know, I was surprised by the well results that you guys turned in in Irion. You know, I think that's not an area that you guys ascribed a lot of value to locations when you picked up those assets. I recognize they're 10,000-foot laterals, but those are better well results than I think other peers in general have turned in in that area. I know you mentioned that the path for there is around a year, so I don't imagine that puts those Irion wells at the top of your stack. Can you talk about where they slot in on your, you know, on your inventory and I guess you already mentioned you have 34 more locations there? Yeah. I mean, we like them, Charles. They're good. They're a little bit gassier. They come on at a pretty high oil rate or oil cut to begin with, but they will get a little bit gassier over time and ultimately end up, you know, 25%-35% oil and the rest gas. We knew going into that acquisition that we weren't gonna have to value the upside, and so we got that acreage, literally those locations for free, didn't pay anything for them, depending on how you wanna value the PDP. We'll drill a little bit of our capital program allocated in that area, won't be 100%. They look really good at $9 gas. Maybe not quite as economic at $6 gas, but still good. It's a good, you know, portfolio mix for us to add those in there. A little cheaper to drill in general, so, you know, the economics still compete, but, you know, it's not gonna command a full rig line. That is helpful detail. Thank you, Robert. Our next question comes from the line of Neal Dingmann with Truist Securities. Please proceed with your question. Good afternoon, guys. Robert, my first question's on Permian development. Specifically, you know, there's certainly, at least this earnings season, been a lot of industry attention on the, you know, people talking about larger scale stack type development. Robert, I was wondering if you or Steve could maybe give details of your upcoming development plans, including, you know, how many zones you might start target or continue to target, and maybe just how in general you plan to attack, you know, Titus and the numerous other plays of yours. Well, Neal, it's a good question, but it's not something that's been new for us. We've been co-developing benches for the last few years in our development plan, whether it's on the Midland side and now on the Delaware side. It depends where you are. In some places, we've actually co-developed four benches at one time. We can continue to do that, you know, as we develop acreage in Upton County, for instance, where we've got the A, B upper, B lower, and C. In the Delaware, it just depends where we are, whether we're gonna develop, you know, the shallower first and second Bone Spring, and then the deeper third and Wolfcamp X, Y, or A, whatever you wanna call it, and then the B even beyond that. Given our size and, you know, our relative cash flows now, we can do larger pads, and we're getting to that point on the New Mexico side finally. We've been doing that on the Midland side for quite some time. It's not, you know, a new concept to us and, it's the most optimum way to develop the reservoirs. Fair enough. That, yeah, that makes a lot of sense. Secondly, maybe for you or Mark, just on shareholder returns, specifically the stock buybacks. You know, I think we estimate your recent 3 million share purchase to be one of the more creative transactions we've seen in months out there anywhere. I'm just wondering, my question then is. You know, will you all continue to remain active in buybacks if, you know, specifically if any of your private holders have further sales? You know, how tied is this to, you know, looking at what your stock price is at? Well, it's definitely related to our stock price and sort of valuation and then other opportunities that we have. This was a unique, maybe a one-off situation, with that particular owner, and we'll continue to evaluate if other opportunities like that come up. It'll be, you know, something that we think about for 2023, as I mentioned, in terms of the overall shareholder return initiatives. It's a little bit early yet still for us to comment on that. Understood. Thank you. Our next question comes from the line of Jeffrey Campbell with Alliance Global Partners. Please proceed with your question. Good afternoon, Robert, and take care of your voice for the World Series. I wanted to approach the Salt Draw results a little bit differently. Yeah, I mean, I thought it was a very impressive result, particularly with the short lateral lengths. Eddy hasn't really been top of mind compared to Midland and Lea Counties. What I wondered was, if any of the 2023 Eddy activity will test any of the large contiguous portion that you have in the county to the northwest of Salt Draw. Yes. Great question, Jeff. The Cletus wells are actually in that block, and we will drill some more wells towards the end of this year and into 2023 as well in different pads over there. We're really pleased with the Cletus results, and they give us a little additional confidence in continuing to develop over there. Much like Irion County and my response there, it's not gonna command a full rig program or one rig, you know, in that area, but good economics and just gives us the ability to, you know, spread out our capital amongst different projects. Right. Although it wasn't a huge number, I noticed that the exploration expense was up pretty significantly relative to recent quarters. I just wonder if you could give us any high level color on what that represented? Yep. That's a good question. Most people don't catch those kind of things. It was one well we had an issue on, and we ended up plugging it. It was on a four-well pad in New Mexico, and we've since drilled out the entire pad, and we did a replacement well, so it's a mechanical issue we had in the shallow portion of the hole and ultimately has not created any other confusion or problems from the execution standpoint other than that little bit of accounting noise. Okay. Well, that's good. Finally, I'll go out on a limb here a little bit. Just wondered if you could provide any color at this time regarding what 2023 might look like. I'm really thinking about, we've got an additional rig in the Delaware Basin relative to most of 2022. Also wondered if we should continue to expect average lateral lengths to increase throughout the portfolio next year as that was a big part of the 2022 effort. Yeah. We're gonna do the best we can to drill the most capital efficient program possible. We'll end up, you know, with some 5,000-footers in there and 7,500s and 10,000-footers. So it'll be sort of a mixed bag. I suspect that what we end up in the two areas this year will probably look similar to next year, where, you know, we'll hopefully have some 15,000-footers we can scatter in there, which really help. We've got 5 rigs running today, and kind of just ballpark thinking about 2023, and, you know, we've obviously done a lot of planning because this program that we have takes a lot of upfront planning. We're planning for 5 rigs for 2023. It's a little bit early to think about what that capital program might cost, but, you know, the Q4 is probably, you know, a good proxy for that at this stage. We'll see as we think about what inflation looks like in 2023. From a production standpoint, you know, we think 5 rigs is about a maintenance program. You know, there is a bit of flush production from Titus that has a pretty steep decline and some of that is wells we brought on the quarter, but really before that too. We think that's about a maintenance program. If the midpoint of our guidance for the Q4 is 100 a day, we think that's about what 5 rigs does for next year. Okay. Well, that's very helpful. I appreciate it. Our next question comes from the line of Subash Chandra with Benchmark. Please proceed with your question. Thanks. Hey, Robert, can you just maybe talk about the sort of field optimization work, workovers, artificial lift, et cetera, how that might, you know, phase out heading into the new year, if at all? Yeah. I mean, from a high level standpoint, Subash, when you make acquisitions, you end up with wells that weren't maintained going through a process of a sale. Steve can give lots of examples of, you know, wells that we needed to spend time on, where equipment is, for one reason or another, stuck in the hole. You know, it was something that we knew going into these acquisitions we were gonna spend some capital on. I think that's, you know, not an ongoing program, and we've got some identified wells we're gonna do some work on, of course. Wells fail, you know, when you have as many wells as we do, wells do fail. I think the big slug of workover from these acquisitions is behind us. Steve? I think so. We peaked out at about 12 workover rigs working at one time, and now we're about in the 6 or 7 range. We went through the crest of that and got everything on. Now we're pretty much back to basic maintenance and some chosen workovers based on economics. All good. Good detail. Thanks. Maybe for Mark, you know, as you talked about paying off, I guess, you know, debt, are you making a distinction between the revolver and the term loan? You know, or should we sort of assume that everything short term is what you're trying to pay off? Yeah, I wouldn't differentiate between the revolving component and the term loan component. They are both part of the same credit facility, and the term loan is priced a little bit higher from a rate standpoint. You know, there's a trade-off there. We could dedicate all of our free cash flow to paying off the term loan piece, but when we do that, the commitments decrease. At some point, if we don't have another use for cash, you could see how it makes sense to pay off term loan. We've not done any of that yet. You know, before year-end, might we pay off some on the term loan? Maybe. It's not something that we've decided or have to decide right now. Right now, we like the flexibility of having more commitments and, you know, the small incremental price that that costs us is a pretty good trade-off right now. Yeah, as we pay down more debt, if there's nothing on the acquisition front, you know, I think probably we'll pay down some of the term loan, but we like having that dry powder available right now. We're pretty close to being half paid down on the total $1.2 billion of commitments. Like that will feel better for us. Really, you know, sort of our target was to get half of paid down by year-end, and even with spending $43 million here this past month on some buybacks, we're about on track for that, maybe even a little bit below that. That feels pretty good, and we'll feel better about paying down some of that term loan permanently as we have more undrawn available. Okay. Gotcha. Final one for me. You know, with the fifth rig coming on, can you sort of maybe talk to your comfort or familiarity with that rig line and, you know, how you sort of see it, you know, being deployed? Or do you think you might need a little bit of time to assess how it performs for you? Well, there's always a learning curve both from the operator standpoint and the service company standpoint, as you put new equipment to work, whether it's a rig or a workover rig or a frac crew. You know, I don't expect it to be up to full efficiency for six months. We've got the acreage position for the three rigs to run in New Mexico and, you know, they're sort of gonna be scattered out for a while, and then at some point, we may find an area we wanna put two of them to work right side by side and kind of fully develop out some acreage. It has been in our planning for the last several months, you know, adding this rig and the types of acquisition, you know, that prompted it sooner than later. We feel pretty good about the ability to just get this rig up in the air and going. Got it. Thanks, guys. Our next question comes from the line of Geoff Jay from Daniel Energy Partners. Please proceed with your question. Hey, guys. You know, one quick question I had on the five-rig program. You know, the annualizing of the Q4 CapEx feels about right, you know, $150-$200 million a rig kinda level. But just wondering, you know, what are the terms of the five rigs? Like, when do those, you know, I guess, how are they laddered, and how much exposure do you have to sort of spot pricing through next year on those rigs? Well, they're all varying contract terms, Jay. Generally, 6 or 12 months. I think we have two of the rigs under 12-month contract. Mm-hmm. The other three are six-month contracts that roll off at different periods of time. In a really bad scenario, we could let a rig go or two, you know, next year. If oil's in this $80-$100 range, we feel really good. As we get close to the end of those terms, we always have the chance to renegotiate. That exposes you to a little higher price, but, you know, with the efficiency we're seeing on these rigs, if we can. You know, if they go up a few thousand dollars a day and we can continue to cut off hours, we're basically keeping our price the same. Right. That makes sense. Then unrelated, but just wondering on the deal front, you know, as I go around, you know, in the middle of the Delaware and talk to guys, basically, you know, it seems like, you know, everybody says every acre is a knife fight, but then you know, every so often, you see deals come to the table anyway. Just wondering what you think the lay of the land is there in the M&A market. Well, things are getting done. I mean, we saw a big deal announced yesterday. Yeah. We've seen some other deals here recently, and some of them pretty sizable in the Permian. I think that the landscape of private equity guys considering sale in 2023 will pick up a little bit. I think the Q4 or the rest of this quarter is gonna be a little bit slow on the deal front. Nothing will get, you know. I doubt a whole lot gets closed between now and year-end. Maybe a few more things get announced. I'm optimistic that there's gonna be plenty of deals for us to look at, and we'll have our plate full evaluating things. We're gonna be cautious about, you know, everything we look at. Excellent. Well, thanks, guys. I appreciate it. Thanks, Geoff. Our next question comes from the line of Jeff Robertson with Water Tower Research. Please proceed with your question. Thank you. Robert or Steve, if I remember correctly, the Eddy County acreage in the Delaware Basin, you all didn't put as high a value on it when you acquired it back in February. Has it. It sounds like the results on some of this drilling you've done are better than what you might have expected when you acquired. Is that fair? They at least met our expectations. It was just the way we allocated value, that we didn't have to allocate a whole lot to the bigger block of acreage in Eddy County. The Salt Draw area is, you know, in the core of the core of the Delaware Basin or at least the northern Delaware Basin. You know, we had high expectations for it, and it proved out like we thought. I wouldn't say you know, we didn't allocate zero to our bigger block in Eddy County, but we're pleased with what we saw, thus we're gonna spend more capital there. Is the three-rig Delaware Basin program the right number of rigs just given some of the permitting and logistical issues that you deal with over there? For now it is. Yeah. It like we've said over and over and over again, we like to walk before we run. We got to the running stage with the two rigs, and now we're gonna pick up the third rig for Delaware, and now we're gonna walk again and make sure that Steve and his group are executing, you know, as well as we can. I know we'll get there, and then we'll figure out if we buy some more acreage or find another deal, whether it makes sense to have a fourth rig. Three, with the acreage footprint and, like you say, the permitting and the infrastructure, is. It feels like it's about the right amount. Thanks. A question, Mark. On the term loan, maybe I have not read this in the 10-Q yet, but you mentioned that if you pay down term loan, it would have impact on the committed amount under the RBL. Is that a one for one, or can you talk a little bit more about that? I didn't see it in the footnote. Yeah, sure. That's right, and really that was the one we closed Titus. The structure is, you know, now we've got a $1.85 billion borrowing base. We have $1.2 billion of total commitments. That's allocated $950 million to a revolving tranche and $250 million to a term loan tranche. The term loan, you know, of course, is fully funded. Any repayments of the term loan, like that's not a revolving piece. If we were to pay off $50 million of term loan, that would reduce the term loan from $250 million to $200 million, and it would reduce the overall commitments from $1.2 billion to $1.15 billion. Okay. Thank you. As a reminder, it is star one to ask a question. If there are no further questions in the queue, I'd like to hand the call back over to Mr. Robert Anderson for closing remarks. Hey, thanks everybody, and we'll look forward to talking to you in the spring once we get through the year-end. Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation. You may disconnect your lines at this time, and have a wonderful day.