Earthstone Energy, Inc. (NYSE:ESTE) Q3 2022 Earnings Conference Call November 3, 2022 1:00 PM ET
Company Participants
Clay Jeansonne – Director, IR
Robert Anderson – President and CEO
Steven Collins – EVP and COO
Mark Lumpkin – EVP and CFO
Conference Call Participants
Charles Meade – Johnson Rice
Neal Dingmann – Truist Securities
Jeffrey Campbell – Alliance Global Partners
Subhasish Chandra – Benchmark
Geoff Jay – Daniel Energy Partners
Jeff Robertson – Water Tower Research
Operator
Good morning, and welcome to Earthstone Energy’s Conference Call. [Operator Instructions] 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.
Clay Jeansonne
Thank you, and welcome to our third quarter 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 third quarter of 2022 earnings announcement and in our Form 10-Q for the third quarter 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 3, 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, and then we’ll have some closing comments from Robert.
I’ll now turn the call over to Robert.
Robert Anderson
Thanks, Clay. And most of you know, Clay, he joined us a few months ago, I’m glad to have him here, and 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 time frame, and we continue to see the benefits from the 7 acquisitions we have closed in the last 7 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 want to thank our existing and recently added workforce for their outstanding hard work and dedication, which enabled us to report the strong financial – the strong third quarter 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. And I’m pleased to report that we reached over 100,000 BOE per day in September.
Our overall outperformance for the third quarter 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. But 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 Stateline 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. And 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 pay down 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 third quarter 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: 1, strategically expanding our operational footprint; 2, increasing our inventory of high rate of return drilling locations; and 3, 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 to provide an update.
Steven Collins
Thanks, Robert. Good morning, everyone. The third quarter 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 cost on our expanded operational footprint and the drilling of high rate of return wells. We continue to be very active in the third quarter, running 2 drilling rigs in the Midland and Northern Delaware Basin. 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 frac operations underway in both the Midland and the Delaware Basins. The teams put in 18 wells in the third quarter 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 that result 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 6 wells in the Lea County in New Mexico near the state line. The Cattlemen Lonesome Dove wells began producing in early September and targeted the First and Second Bone Springs. The 6 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 73% oil cut. We expect these wells to have an average payout of less than 6 months. Also in the Northern Delaware Basin on our Chisholm acreage, we acquired earlier this year, we completed 6 additional wells on 4 separate pads. I’ll highlight a couple of those.
We brought on 4 wells during the quarter in Eddy County in New Mexico. The 2 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 oil cut of around 70%. In early September, we turned to sales 2 wells in the Salt Draw pad, which had an average IP-30 of over 1,570 BOE per day with laterals of 4,700 feet and an oil cut of approximately 77%. Both wells targeted the Second Bone Spring interval. And finally, in the Midland Basin, I’d like to highlight the Barnhart pad in Irion County, Texas. This 5-well pad was developed on the acreage we acquired from Tracker in July of ’21.
These wells were drilled with a lateral length of approximately 10,000 feet. We have been pleased with the results from these 5 wells. The pad began producing in mid-August with an average IP-30 rate of 1,170 BOE per day and is 81% oil. On average, the drilling and completion costs for each well was only $8 million. And given the production rate and low-cost nature of these wells, we expect them the 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 recognized 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 need to work at the time of the acquisitions. The goal is to reduce failure rates and increase run times by optimizing lift methods and improving mechanical designs.
We estimate we have spent a little over $7 million over the last 2 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 is 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.
Mark Lumpkin
Thank you, Steve. Similar during 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 electric 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 a 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 third quarter 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. Third quarter 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 second quarter.
Free cash flow for the quarter was approximately $175 million, which was a 7% increase from the second quarter. For the 9 months ended September 30, we generated 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 and total debt of just under $1.2 billion. Our debt to annualized EBITDAX ratio for the third quarter was 0.8x, which is ahead of our plan. We plan to continue to use free cash flow to reduce debt and fully expect to remain below 1x debt to adjusted EBITDA going forward.
From a production standpoint, we are pleased to surpass the high end of our third quarter 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 fourth quarter 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 third quarter, which was a little bit lower than our prior third quarter expectations. For the fourth quarter, we expect capital to range from $170 million to $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 fourth quarter by about 30% compared to our prior plan and our guidance, which is really resulting in significantly improved capital efficiency with the longer laterals. And to a lesser degree, we also expect higher non-op capital activity levels in the fourth quarter.
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 fourth quarter, 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 fourth quarter at around 54% for oil and 62% for gas. And for 2023, based on the midpoint of fourth quarter guidance, we’re hedged about 35% oil and about 31% for gas. I would note that we continue 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 exports gases, we do have a bit of gas that is exports to Houston Ship Channel versus to WAHA. And we’ve got a good percentage of 2024 hedge for WAHA basis as well.
Finally, I’d like to highlight the significant increase in our current train liquidity. For the third quarter, trading volumes averaged 1.8 million shares per day or $24 million of value traded per day, which was an increase of about 8% over the second quarter. We believe this added trade liquidity will benefit existing and future shareholders, and we’re really pleased to see the improvements in the train liquidity.
With that, I’ll turn it back over to Robert for closing comments.
Robert Anderson
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 2 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 workforces constant dedication and hard work as important has been the continued commitment and support of our shareholders.
So with that, operator, I’d like to turn the call back to you to take some questions.
Question-and-Answer Session
Operator
[Operator Instructions] Our first question comes from the line of Charles Meade with Johnson Rice.
Charles Meade
Robert, it was good to see those Delaware Basin results on those – your 2 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? And second, what the opportunities are going forward to further improve those well results? It seems like the most – those obvious avenue to do that might be longer laterals, but that’s probably not the only one. So if you could just talk about those 2 aspects?
Robert Anderson
Yes. We really like the results. As Steve mentioned, it kind of, in some cases, met our kind of acquisition cases. And in a couple of cases, maybe we’re 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 kind of lined up with the way the outcome of these wells are.
Probably it’s a few trades happen that allow us to do longer laterals, which is super important, but more importantly, it’s just controlling your destiny. So 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 depending on where we’re drilling and what horizon and as we co-develop different horizons together, they’re not all going to 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.
Charles Meade
And then just sticking on the theme of low results. I was surprised by the wherewithal’s that you guys turned in, in Irion. And I think that, that’s not an area that you guys ascribed a lot of value to locations when you picked up those assets. But I recognize there 10,000 foot laterals, but those are better well results than I think other peers in general have turned in, in that area. So 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. But can you talk about where they slot in on your inventory? And I guess you already mentioned you have 34 more locations there.
Robert Anderson
Yes. 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 25% to 35% oil and the rest gas. But we knew going into that acquisition that we weren’t going to 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 want to value the PDP. And we’ll drill a little bit of our capital program allocated in that area. I won’t be 100%. They look really good at $9 gas, maybe not quite as economic at $6 gas, but still good. And it’s a good portfolio mix for us to add those in there.
A little cheaper to drill in general, so the economics still compete, but it’s not going to command a full rig line.
Operator
Our next question comes from the line of Neal Dingmann with Truist Securities.
Neal Dingmann
Rob, my first question is on Permian development. Specifically, there’s certainly at least this earnings season been a lot of industry attention on people talking about larger scale stack type development. So Robert, I was wondering if you or Steve can maybe give details of your upcoming development plans, including how many zones you might start target or continue to target? And maybe just how in general you plan to attack Titus and the numerous other players of yours?
Robert Anderson
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 4 benches at one time. And we can continue to do that as we develop acreage in Upton County, for instance, where we’ve got the A, a B, Upper B, Lower and a C. And in the Delaware, it just depends where we are, whether we’re going to develop the shallower first and second Bone Springs and then the deeper third and Wolfcamp X, Y or A or whatever you want to call it, and then the B even beyond that.
So given our size and our relative cash flows now, we can do larger pads, and we’re getting to that point on the New Mexico side finally. But we’ve been doing that on the Midland side for quite some time. So it’s not a new concept to us, and it’s the most optimum way to develop the reservoirs.
Neal Dingmann
And then secondly, maybe for you or Mark, just on shareholder returns specifically to stock buybacks. I think we estimate, I think your recent 3 million share purchase to be one of the more accretive transactions we’ve seen in months out there anywhere. And I’m just wondering, my question then is, will you all continue to remain active in buybacks if specifically, if any of your private holders have further sales? And how tied is this to looking at what your stock price is at?
Robert Anderson
Well, it’s definitely related to our stock price and sort of valuation and then other opportunities that we have. So 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 will be 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.
Operator
Our next question comes from the line of Jeffrey Campbell with Alliance Global Partners.
Jeffrey Campbell
I wanted to approach the Salt Draw results a little bit differently. I mean, I thought it was a very impressive result, particularly with the short lateral lengths and Eddy hasn’t really been top of mind compared to Middle and in Lea Counties. But 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?
Robert Anderson
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 in my response there, it’s not going to command a full rig program or 1 rig in that area, but good economics and just gives us the ability to spread out our capital amongst different projects.
Jeffrey Campbell
I’ll go on 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?
Robert Anderson
Yes. That’s a good question. And most people don’t catch those kind of things. It was one well we had an issue on and we ended up plugging it, and it was on a 4-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, a little bit of accounting noise.
Jeffrey Campbell
And finally, I go out on the 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. And also wonder if we should continue to expect average lateral length to increase throughout the portfolio next year as it was a big part of the 2022 effort?
Robert Anderson
Yes. We’re going to do the best we can to drill the most capital-efficient program possible. We’ll end up with some 5,000 footers in there and 7,500 and 10,000 footers. So it will be sort of a mixed bag. I suspect that what we end up in the 2 areas this year will probably look similar to next year where 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 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. And it’s a little bit early to think about what that capital program might cost. But the fourth quarter is probably a good proxy for that at this stage, but we’ll see as we think about what inflation looks like in 2023.
Mark Lumpkin
And from a production standpoint, we think 5 rigs is about a maintenance program. There is a bit of flush production from Titus that has a pretty steep decline, and some of that as well as we brought in the quarter, but really before that, too. So we think that’s about a maintenance program of the midpoint of our guidance for the fourth quarter is 100 a day. We think that’s about what 5 rigs does for next year.
Operator
Our next question comes from the line of Subhasish Chandra with Benchmark.
Subhasish Chandra
Robert, can you just maybe talk about the sort of field optimization work, workovers [articulates] et cetera, how that might phase out heading into the new year, if at all?
Robert Anderson
Yes. I mean, from a high-level standpoint, Subhash, when you make acquisitions, you end up with wells that weren’t maintained going through a process of a sale. And Steve can give lots of examples of wells that we needed to spend time on where equipment is for one reason or another, stuck in the hole. And it was something that we knew going into these acquisitions, we were going to spend some capital on. I think that’s not an ongoing program, and we’ve got some identified wells we’re going to do some work on, of course. And well-fail when you have as many wells as we do, wells do fail. But I think the big slug of workover from these acquisitions is behind us, Steve?
Steven Collins
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. So we went through the crest of that and got everything on. And now we’re pretty much back to basic maintenance and some chosen workovers based on economics.
Subhasish Chandra
Maybe for Mark, as you talked about paying off, I guess, debt, are you making a distinction between the revolver and the term loan or should we sort of assume that everything short-term is what you’re trying to pay off?
Mark Lumpkin
Yes. 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. Yes, there’s a trade-off there, if 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 got not done any of that yet. Before year-end, might we pay off some on the term-loan, maybe, but it’s not something that we’ve decided or have to decide right now.
So right now, we like the flexibility of having more commitments and the small incremental price that, that cost us is a pretty good trade-off right now. Yes, as we pay down more debt, if there’s nothing on the acquisition front, 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, that will feel better for us. And really 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. So that feels pretty good, and we’ll feel better about paying down some of that term-loan permanently as we have more undrawn available.
Subhasish Chandra
And final one for me. With the fifth rig coming on, can you sort of maybe talk to your comfort of familiarity with that rig line and how you sort of see it being deployed or do you think you might need a little bit of time to assess how it performs for you?
Robert Anderson
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. So I don’t expect it to be up to full efficiency for 6 months. But we’ve got the acreage position for the 3 rigs to run in New Mexico, and they’re sort of going to be scattered out for a while. And then at some point, you may find an area we want to put 2 of them to work right side-by-side and kind of fully develop out some acreage. So it’s all in our – it has been in our planning for the last several months, adding this rig and the Titus acquisition was prompted it sooner than later. So we feel pretty good about the ability to just get this rig up in the air and going.
Operator
Our next question comes from the line of Geoff Jay from Daniel Energy Partners.
Geoff Jay
One quick question I had on the 5 rig program. The annualizing of the fourth quarter CapEx feels about right, $150 million to $200 million a rig kind of level. But just wondering, what are the terms of the 5 rigs? Like, when do those – I guess, how are they laddered and how much exposure do you have to sort of spot pricing through next year on those rigs?
Robert Anderson
Well, they’re all varying contract terms, Jay, generally 6 or 12 months. I think we have 2 of the rigs under 12-month contract and the other 3 or 6-month contracts that roll off at different periods of time. So in a really bad scenario, we could let a rig go or 2 next year. But if oil is in this $80 to $100 range, we feel really good. And 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 with the efficiency we’re seeing on these rigs, 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.
Geoff Jay
And then unrelated, but just wondering on the deal front, as I go around in the middle of the Delaware and talk to guys, basically, it seems like everybody says every acre is a knife fight. But then you – every so often you see deals come to the table anyway. Just wondering what do you think the lay of the land is there in the M&A market?
Robert Anderson
Well, things are getting done. I mean, we saw a big deal announced yesterday. We’ve seen some other deals here recently and some of them are 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 fourth quarter or the rest of this quarter is going to be a little bit slow on the deal front, and nothing will get – I doubt a whole lot gets closed between now and year-end, maybe a few more things get announced. But I’m optimistic that there’s going to be plenty of deals for us to look at, and we’ll have our plate full evaluating things, but we’re going to be cautious about everything we look at.
Operator
Our next question comes from the line of Jeff Robertson with Water Tower Research.
Jeffrey Robertson
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. 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?
Robert Anderson
They at least met our expectations, and 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 in the core of the core of the Delaware Basin or at least the Northern Delaware Basin. So we had high expectations for it and it proved out like we thought. So I wouldn’t say we didn’t allocate 0 to our bigger block in Eddy County, but we’re pleased with what we saw. Thus, we’re going to spend more capital.
Jeffrey Robertson
Is the 3-rig Delaware Basin program, the right number of rigs just given some of the permitting and logistical issues that you deal with over there?
Robert Anderson
For now, it is. Yes, like we’ve said over and over and over again, we like to walk before we run. We were – we got to the running stage with the 2 rigs, and now we’re going to pick up the third rig for Delaware. And now we’re going to walk again and make sure that Steve and his group are executing as well as we can, and 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. But 3, with the acreage footprint and like you say, the permitting and infrastructures, it feels like it’s about the right amount.
Jeffrey Robertson
Question on 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?
Mark Lumpkin
Yes, sure. That’s right. And really that was the one closed tides. So the structure is, 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, of course, is fully funded. Any repayments of the term-loan, like, that’s not a revolving piece. So 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 will reduce the overall commitment from $1.2 billion to $1.15 billion.
Operator
[Operator Instructions] There are no further questions in the queue. I’d like to hand the call back over to Mr. Robert Anderson for closing remarks.
Robert Anderson
Thanks, everybody, and we’ll look forward to talking to you in the spring once we get through the year-end.
Operator
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.
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