To get us rolling, and we'll leave plenty of time for Q&A. First, a few disclaimers that I'll point you to in our slide deck that we posted online this morning. Most of you know us quite well, but for those who do not, I'll just point out that we have really focused over the past decade on identifying, owning, and developing high-return assets, operating them well for capital efficiency and free cash flow generation, and maintaining a leadership position among our peers in sustainability and stewardship. Quick summary, and we've used this for quite a while now. We're a premier operator of top-tier assets that focuses on operational execution, returns capital to stockholders, and drives for expansion of our portfolio of top-tier inventory in the lower 48 states.
Rather than talk over one key result again, I decided today to just focus on what really differentiates us from our peers. This is about our track record. It all starts with deep and experienced geoscience and engineering capability. While SM Energy has operated in the lower 48 in almost all the basins over our 117 years of history, I'll concentrate on three where we have distinguished ourselves. I'm going to start with Howard County. Many of you know this, but when we entered the county in 2016, there were only about 79 horizontal wells that had tested just three intervals. However, there were a lot of vertical wells, and that meant there was a lot of data in the basin and in that county.
With the data from vertical wells, we saw an overlooked horizontal play where previous industry concerns about the presence of carbonates turned out to be incorrect. Pundits really thought that we had moved too far east. That turned out not to be the case. Howard County rapidly became a top 10 county in the industry in terms of drilling rigs, given the attractive economics that we were demonstrating. Now, you look at it just nine years later, and there are over 4,900 horizontal wells in the county producing from as many as eight intervals. That is right, from 79wells- 4,900 wells and from three up to as many as eight intervals in less than a decade. At the bottom of the slide, same story goes for the Austin Chalk play in Webb and Dimmitt counties in southwest of San Antonio in the western Eagle Ford.
In 2018, when we opened up this play, there were only eight industry horizontal wells in this general area, and economics were dismissed as high break-even or $80 per barrel. To us, we view that as an opportunity. That is something we can really go after to really create shareholder value. Now you look at it, there are over 475 industry wells. There are 465 SM Energy locations, about 150 of which we have drilled up, and the break-even prices are down to $44 a barrel. That is the impact of technology and recognition of really the rock that is in location. The next, what is next for SM Energy? It is the Uinta Basin, and it is the next chapter of the same playbook that I just went over. This summarizes the metrics well. Many people do not know this, but that basin has been producing conventionally for over 75 years.
There's extensive data, and there's been quite a bit of de-risking from over 8,500 vertical wells. Now you look at it, and there's 4,000 feet of stacked pay, over pressured source rocks, which is a key success factor for unconventional plays. The lower cube, which is the middle section of the 4,000 feet, has over 800 industry horizontal wells, of which SM has about 200. The upper cube has about 18 industry horizontal wells. You are going from a past of limited activity, constrained oil takeaway, uncertain economic viability, and industry skepticism, and actually not many companies that were at the cutting edge of the industry in the way of horizontal wells. Now you look at it, there's sufficient oil takeaway. It's really high-quality inventory in terms of break-evens. It's competitive with top-tier basins.
In fact, the margins we see are almost the same as the Permian Basin, and there's significant upside. We view a significant future, first of all, in developing the known areas, the lower cube, identifying more inventory in the upper cube, and then there's the deep cube, which we're still in the early stages of figuring out what the ultimate potential is. I'll come back to Uinta Basin and talk about how the integration's going in a bit here. Technology is part of our DNA. I'm not going to elaborate on this one, but why are we able to be the first to drive a play into economic territory that others have overlooked? It really comes down to that experienced technical team and the longstanding support for developing the tools and the infrastructure needed to get exceptional results.
This slide summarizes some of that technology, but I'm going to turn to specific examples. This is about the process we employ, our ability to forecast, the results we achieve, and the ability to iterate back and forth to continually improve those well results. Before we get ever convinced drilling on a new pad, we utilize an extensive database of our wells and others' wells from data trades. We simulate our stacked pay configuration and the well interactions with numerous completion designs. In this case, we tested 25,000 unique designs, all premised on data, and determined that the best value proposition involves somewhat more capital than the Midland Basin average. This is a Midland Basin example. Basically, we showed that going from that orange to the blue achieved an incredible amount of value add for the capital that was spent on that incremental.
Taking this just a step further, this is actually the forecast of the 50 best horizontal well designs, and we chose the one that optimized the development from all considerations. That means the value from the DSU. If you go to the very top, that might just be one well in a DSU, but that does not optimize the value. In this case, you will see the dotted black line is the Midland Basin average well design, and the blue is the SM well design, which optimizes from all factors in a full drilling spacing unit. You might look at this and you say, "Well, does not everyone do that? I mean, what is the big deal?" Astonishingly, no.
We obviously operate, and then we participate in other non-operated wells, and we can tell you that optimization is still, there's some art to it, but there's a lot of science behind it, and that's what we employ there. Now let's go to the next step, which is the actual well results. Here you can see from these subsurface design optimization, when we're operating in an area in Howard County, this example is our operated wells, all of them over a period of time versus pure operated wells and about 32% better performance. This is cumulative oil production per 10,000 foot of lateral. Likewise, in the Austin Chalk, there it's 42% better. I'll flip through these relatively quickly here. We also have identified new targets, and that's really our geoscience team. This is the Woodford Barnett.
Here you can see our first two wells in the play are about 50% better than the nearby pure operated wells. That is just a function of that ability to optimize performance. That is pre-drill simulation that drives what that performance is. Going to the north in the Midland Basin, our Klondike wells, which we just announced this acquisition actually at the JPMorgan conference two years ago. You will see there we are showing the delineation program that we are conducting. The red was our acquisition model that we were using two years ago. You can see the eight wells that we have delineated to date. We will bring another six online this year to confirm the overall benefits of that play. Now let us turn to the Uinta. I am not going to elaborate on this one.
We talked about it at the time of the acquisition last year, but the lower cube wells produce a substantial amount of oil in their first two years of life, substantially above Midland Basin and Gulf Coast wells. That is key to this. The point I wanted to make from this slide was Enverus came out and added more inventory to us, a 28% uptick in their view. We obviously have taken a forward-looking view. They are looking rearward at how proven a play is. That is a material shift. We like the quote here, "Those recent buyers may be onto something," and we completely agree with that sentiment. Now, how is the integration going?
First of all, the driver of our first quarter production beat just recently that we announced in late April was we optimized marketing, and that boosted our oil takeaway and increased the volumes we were able to take away and sell. We had significant capital efficiency gains around record pumping times. We basically set new records on the total longest and deepest wells in the Uinta Basin. We used a centralized e-fleet using residue gas to make the Simulfrac record that ProFrac announced after March, which was the record month. The key thing that drives cost down is we have an operated sand mine. It started in October, and that eliminates all the 80 mines of truck transport to other sand mines that were used before. More recently, and you'll see on the lower right here, that's a conveyor belt we installed.
Even within the field from our sand mine, we've eliminated the trucking to get costs even down further. That was another $15-$30 per lateral foot. Obviously, from an ESG perspective, that's positive and a cost perspective. We're really pleased with not only what the predecessor operator, XCL, did, but what possibilities there are to get the well cost down even further. Just quickly, in the slide deck, you may notice that we've got three more Austin Chalk wells that we've just announced on a pad. I haven't done the math here, but I just saw an analyst said that this was 28% better than the previous pad that we announced. Pleased to see that, and this is way at the northern edge of our position, how well those wells are doing with relatively high oil percentage and long lateral lengths.
Overall, we've shown this slide before just how we keep getting more efficient from a D&C cost basis in the Midland Basin and in South Texas, and we expect that to continue. Everyone says, "Hey, are you in the eighth inning or the ninth inning?" They asked that in 2018, and I would say we keep blowing out new records all the time. That is just a testament to the entire industry and what we're able to do there. Finally, on the operational excellence, we just took our board and executives to look at the field in Utah and check out all phases of production. I wanted to point out from Rystad perspective, we're number one among oil-focused operators for ESG scores, number three overall, including gas operators. That is really what I was going to cover real briefly, Zack, and then I'll open it to Q&A.
Oh, balance sheet-wise, those of you who want to know where we stand balance sheet-wise, we look at we got a maturity in 2026 and maturity in 2027, and our focus is on debt repayment. As soon as we get through our two times levered, then we'll go ahead and recommence our buyback program on stock. This goes over that. We've got cumulative capital return to stockholders over the last three years has been $567 million, and we'll continue the dividend and the buyback program. With that, I'll hand it over.
Thanks, Herb. A number of your E&P peers slowed activity with Q1 earnings just given lower oil prices and economic uncertainty, but SM maintained the prior budget.
Can you talk about why you believe that was the right thing to do in this macro environment, and what would you need to see to slow or alternatively to speed up activity?
Right. Zack, it's a great question, very topical, post-liberation day. It's really the program we laid out, it was fortuitous that we had already planned to drop from nine rigs to six rigs, and by end of first quarter, we were already down to seven rigs. You say, "Well, why were you doing that, and why don't you continue to drop further?" Really, we're about maximizing free cash flow over the next three years. We didn't know how long a downturn in crude might last, and the events of the last couple of weeks were very hard to forecast.
In the Uinta, we have a strategic desire to understand more intervals and to assess the best way to optimize performance. We want to continue that program because we'll wind up with better and better wells over time. In the other basins, we wanted to see South Texas is gassier, Permian is oilier like the Uinta. We wanted to see what gas prices would really do. Was there a sustained uplift in what that commodity price would be that would underpin any sort of shift in allocation? We chose to keep things the same, let things sort out, and we also increased our hedges, and you'll see that in this latest slide deck that we posted this morning. We're hedged better for oil. We're up to over 40% on the next year's oil hedging. Yeah, you mentioned that.
I think you added around 15,000 barrels a day of hedges in 2026. With the volatility, can you talk a little bit more about how you're thinking about hedging? You clearly stepped in when there was some volatility here. Do you want to add more to the hedge book, or do you think you're good for now?
Right. No, it is always a fundamental question. We hedge for two purposes. One is for the balance sheet, and the other is for our basis risk in certain basins we operate. When we tie our hedging level to the balance sheet and what leverage we're running at and our forecast of the leverage, there is a trailing 12-month dimension, and there is a forward-looking dimension.
As commodity prices drop, we forecast what our leverage might be, and we want to cover that to be in a really good position from a free cash flow standpoint. When you look at all the dimensions, that is really what drives us. Yeah, we are now hedged to a little bit higher level than we were before, and that is because the risk of a lower commodity price is a bit higher than it was at the start of the year.
You mentioned this a little bit in your first answer in South Texas wanting to see what the gas price would end up. How are you thinking about capital allocation between the basins here? I think we think, and a lot of investors think, that there is a bullish case for gas in 2026. You have seen the strip move quite a bit higher.
Are we to a level where you might allocate a little more capital to South Texas, potentially to that southern part of the play that's more dry gas focused?
Zack, it's an excellent question, and we view it as a big opportunity that we have the ability to devote more capital to the gassier play. I would say we take a measured approach. First, on the existing program, we like really smooth operations that are as capital efficient as possible. We will not suddenly move a rig from one location to another and bear the consequences of that additional cost from moving it. It's very good to have built up to a certain duck count level, use a simulfrac as much as possible to keep those well costs down and allow you, you're more resilient to commodity price downturns.
When we look forward, we really look like a year or year two, and we like what we're seeing on potential AI-related power demand, which would be supplied by gas fundamentally. We like that and the LNG plant growth. Assuming the international markets are there to underpin the LNG production and the LNG cargoes being shipped out, that's also a positive. We also know it's relatively easy to bring gas online to production. When you're in an over $3.50 gas world, it's quite attractive to drill for gas. Those elements can be attractive, but we want to see that sort of sustained. We view that as something that we can do on our annual cycle of assessing the budget and the plan for the next two to three years to maximize free cash flow generation.
If we were to make a change and you told me that oil was going to be at $50 a barrel and gas was going to be north of $4, that's when we really evaluate. We run the scenarios and we'll say, "This is a better plan than our previous plan," and we would optimize.
Thanks. You have a unique operating position where you're across three basins and you have assets that produce kind of each commodity. Can you talk a little bit about how the returns compare across each basin? How does the Uinta compare to South Texas and the Midland?
Yeah. This is where we really consider ourselves blessed, but it wasn't just happenstance.
If you looked at our portfolio 12 years ago, we had a lot of tier two assets that we over time really recognized what it took to have a tier one asset, and we moved ourselves into those three basins. We were already in South Texas, but we identified the Austin Chalk, which was quite a bit better. When you go through that whole program, Zack, say again the question you had there. Let me make sure I got that straight. The question, yeah.
Oh, the compare and contrast the returns across your three operating areas?
I always go to the mid-cycle pricing, and mid-cycle pricing, so let's call it $70 and $3.25-$3.50, there the returns are about equal across all the assets. If you're allocating between, say, we're running two rigs, two rigs, and two rigs, we would be balanced there.
We could move capital between in an efficient manner, and it would not make much difference to the free cash flow generation over the next three years. If you are in that high commodity price environment for oil, then you would shift more towards the Permian and Uinta. If you were in a high gas, you could shift some more to South Texas, but it would not be a dramatic amount of shift in there. That is really what I call mid-cycle pricing, comparable returns.
Y'all took over operations officially in the Uinta almost around six months ago. Can you just talk about how operations are going so far? What have been some of your early wins there that you have seen?
Yeah, it has been a great run. First of all, we made offers to all the field employees of XCL, and we had 100% acceptance, and those were extended October 2nd.
They came online. People came on board on January 1st. From an execution standpoint, we were surprised to see how advanced XCL was in their operations. Part of that was they took over the acreage in early 2020 when necessity was the mother of invention, and they came up with really ways to reduce cost across the board. They looked at how do they reduce their sand trucking costs, how do they drill better wells. They went through everything. When we looked at it, they put capital into water infrastructure so there would be 100% recycle capability. They introduced a new sand mine, which just started up in October. They brought in an EFRAC and supplied the gas to a turbine to generate the power for the EFRAC from residue gas coming off a plant nearby. That lowered the cost significantly for them.
We wound up with the benefits of a lot of infrastructure investment that lowered our costs. What SM Energy brings to the table with those operational excellence items is really on the subsurface side, the ability to model the stacked pay from our experience in the Permian Basin and South Texas. That stacked pay capability is really the ability to simulate the interaction between the wells. You can optimize the spacing and ultimately optimize your returns and your incremental capital returns in particular. We look at how many wells XCL might have put into a lower cube area. We would probably use larger completions, more fluid volumes, space them a bit wider, and wind up with much more value out of those. You will not see our actual designs online until early next year, but we have already improved individual wells.
The first thing when we started, we encouraged them to drill 15,000-foot laterals rather than 10,000-foot laterals. There is an element of capital efficiency there. We did do some modifications in the completion design, and those have been beneficial also. That was a long-winded way to answer that one, Zack.
No, that is great detail. I also wanted to ask on your exploration plays in the Midland Basin. You mentioned this a little bit in your prepared remarks, but Klondike and Dawson County, and then the Barnett Woodford on your Sweetie Pack acreage. How do you think about exploration in the future and maybe update us on what is the latest on both of those areas?
Okay. Zack, we have long held the belief in a 117-year-old company that an E&P company cannot really exist unless it has the ability to produce a play from ground zero.
It is a fundamental ability, a capability that we believe our team needs to have. The lower 48 today is not what it was 15 years ago. What it does have that is unique compared to almost anywhere I know of internationally is an incredible amount of vertical well data. Between the AI and our team's capabilities that are there, how much data we can churn through to identify new plays is just remarkable. You will see even the Austin Chalk was really the result of this. This is an area where we had drilled 600 Eagle Ford wells right through the Austin Chalk. I still bother our geologists by saying, "Why did it take you 10 years to figure this out?" Look at it this way. There it was on our own acreage, and it took us 10 years to figure out.
Just think what's out there in all those other basins where we can apply the tools and skills we have that things have been overlooked. When we went in just two years ago, when we went into Dawson County, everyone said that was too far north. It wouldn't work. There we did more or less a conventional play. It's a migrated oil play from the hotter central part of the basin, but it migrated through a sandstone up to the north, and we saw that and did that. In the Uinta, basically, it's just smaller operators who have operated there for years, or it was off, not in the focus areas of some of the bigger companies that were there. To us, that smacked of opportunity.
Y'all entered the year running nine rigs.
You've talked about plans to get down to six rigs by the time we exit the year. I know it's early, but how should we be thinking about 2026 activity levels? Is six rigs the right run rate? If you're at a six-rig program, would that grow production, or how should we be thinking about volumes?
Right, right. When you think about 2026, we haven't budgeted for 2026 yet. We don't know what the commodity prices are yet. There's quite a bit of volatility going on right now. We'll get into that process in November to January. The way to look at it is six rigs is kind of flattish production for us. One caveat is if we shifted more capital to the gassy areas, you actually wind up with some BOE growth.
If you stay in the oily areas, it's really flattish from that standpoint. I can't tell you where we'll be. If you're in $50 oil and $3 gas, it gets tough to maintain a program like that. If you're in $60 north on oil and $4 gas, it's pretty easy to run a program like that and generate free cash flow and reduce the debt below our target.
You mentioned the debt there. Following the XCL acquisition, which was all cash, you noted plans to pull back on buybacks and focus on debt reduction with a goal of one turn of leverage before you'd restart that share buyback program. At current strip pricing, and I realize this has been volatile recently, when do you expect to hit that leverage target? When could we expect you to be buying back stock again?
Okay. Yeah.
Zack, I don't know if this will help you answer that, but when we came out with our budget in February, we said that at $70 and $3.25, we'd get to our one-time leverage target at end of third quarter, early fourth quarter. First quarter looked good. Second quarter, commodity prices are lower. Can't quite tell you where third quarter is going to be yet, but we're making good progress in terms of what we see, but it'll really depend where commodity prices are. We're not that far on a pro forma basis. At the end of the first quarter, we were 1.1 times. We reported 1.3, but we could only count two quarters of the Uinta production. Pro forma, if we brought in two quarters of XCL, then that would put us at 1.1. We're not far. Strong balance sheet.
We also are making sure that in a low cycle price time, like it looks like we're in, that we can sustain and do well.
We've seen some activity come out industry-wide with the commodity price volatility. Have y'all started to see any cost deflation yet? Maybe remind us how contracted y'all are on your rigs and your frac equipment?
Yeah, it's a great question. It's been the topic of the day. We are seeing cost deflation. It's very specific service aspect driven. I would say steel has been an area where we pre-bought, so we don't have much exposure this year, but there is some slight increase on steel, but it's a small component of our cost. Rigs and pumping services are in much better shape. We see slight deflation there, but not significant. Nothing double digits in any way.
It's all relatively small, but there's continued cost pressure with the commodity prices where they are and activity levels dropping the way they are. No deflation in labor costs whatsoever.
You mentioned utilizing Simulfrac earlier. Can you talk about how SM is using that? How much of the 2025 program will utilize Simulfrac? Maybe give us your thoughts on Trammel Frac as well, which we've heard some of your peers talk about.
Okay. We will Simulfrac wherever we can. First, in South Texas, the spacing of the pads is pretty significant. There's not as many wells per pad. There, we zipper frac. We are currently running a Simulfrac in the Permian and in the Uinta. In the Uinta, they call it double barrel.
We have kind of a unique situation in the Uinta where we don't have to move that frac fleet much at all because we have the ability to remote frac as much as three miles away. We can do two pads at once. Minimizing those moves leads to a lot of efficiency. In the Permian, how much we run the Simulfrac will depend really on the pad sizes. If the pad's smaller or if it's delineating like up in Dawson County, we really can't Simulfrac there. We'd use a Zipper Frac in that situation. I can't give you a percentage on how much is Simulfrac versus zipper frac, but we'll use Simulfrac as much as we can feasibly.
Trammel Frac, we do not quite see the incremental benefit as much, but you would also need to have relatively large pads or nearby large pads and remote fracking. We have not seen sufficient benefit to try the Zipper Frac at this stage.
Thanks, sir. We are at the end of our time here, but appreciate you and the SM team being at our conference this year.
Okay. Thanks a lot, Zack. Appreciate it.