SM Energy Marries Wildcatting and Analytics in the Oil Patch

Founded more than 115 years ago, then-Minnesota-based St. Mary Parish Land Co. started out buying up acreage in its namesake southern Louisiana parish with an eye toward the cattle business.

That didn’t work out so well. Fortunately, oil and gas did. While SM Energy has a truncated name and no longer focuses on Louisiana, the E&P is pioneering expansions of the Midland Basin, leading Austin Chalk growth in South Texas and growing rapidly in the emerging Uinta Basin in Utah.

SM’s data-heavy wildcatting approach has helped expand the Midland Basin both to the north and south through different benches, and extend its success in the Chalk as the Eagle Ford Shale matured.

SM President and CEO Herb Vogel spoke with Oil and Gas Investor’s Jordan Blum to discuss the Texas growth and surprising acquisition of XCL Resources last year in the Uinta in a unique deal with fellow buyer Northern Oil and Gas—coincidentally based out of Minnesota.

Jordan Blum: I wanted to start out delving into SM’s history. My first full-time job was in St. Mary Parish in Louisiana where SM got its start and its name.

Herb Vogel: It’s actually a pretty fascinating story when you get into it. It was a Minneapolis company founded in 1908, and they bought, like, 17,000 acres [in St. Mary Parish]. Ultimately, it became 25,000 acres. The original intention was to do cattle ranching on it, and that didn’t go well through the first tropical storm.

But they were fortunate in the hydrocarbons. They farmed out leases to different companies like Texaco and ARCO. But, in 1938, they had their first big discovery and, by the 1960s, they had over a 1 Tcf equivalent, primarily gas. There was also oil and some of it was relatively deep, 10,000 ft-type depth. Then they went actually international for years in the 1980s and ’90s, but then expanded all through the Lower 48 and Anadarko Basin, the Bakken, and had a little Permian, initially.

The company really expanded, and it was quite broad by the time it went public in 1992 on the Nasdaq. It was an acquire and exploit company—buying properties, figuring out how to get some more and then flipping them. Really, in 2007 and 2008 is when the strategy shifted to unconventional resource development. It was really just auspicious timing. It’s put us really at the cutting edge.

JB: Obviously, you’ve have had a lot of growth in the Midland Basin, and now you went to the Uinta Basin with the XCL Resources deal. But I wanted to go back to the early shale boom in South Texas and SM’s Maverick Basin deal that was almost kind of fortuitous in the timing with the Eagle Ford Shale boom coinciding with everything SM was doing.

HV: Yeah, the whole principle of the company has been to get into stacked pay resources, and South Texas is a great example of that. They originally went in for the shallow gas Olmos [Formation]. Then, there was the deeper gas Pearsall [Shale] that had potential. But, then, the Eagle Ford is what really hit after Petrohawk [Energy] hit. We were in the gas window all the way to the retrograde condensate window to volatile oil, and we drilled 600 wells in the Eagle Ford. Every one of those wells went right through the Austin Chalk.

I hand it to one geologist who was really looking closely at all the wells that got to the top of the Eagle Ford and were close to the Austin Chalk. He saw the yields were higher. We said, “Why is that?” So, in 2018, we drilled the first Austin Chalk-dedicated lateral. They requested a core, and they saw that there was a much better interval to land. That’s in 2019. I still remember in December 2019, and we hit the best Austin Chalk well with a short lateral because we were just testing it. It was a 6,000-ft lateral. And then we knew we were off to the races on it because that had high productivity, had a lot of permeability and was quite rich. It was high, high yield condensate or volatile oil. At the time, we thought we could get 400 locations. Since that time, we’ve said there’s about 465 locations, and those are with relatively long laterals, too. That was just really one geologist saying, “Why is it this way?” And then digging into it, and we supported looking at it.

We have a lot of running room in the Austin Chalk. You can look at it this way. We drilled 600 Eagle Ford wells, and that was on our initial acreage acquisition. Then we found the Austin Chalk with another 465 locations after the fact. We still have Eagle Ford inventory, which some of it’s gassy and we don’t even count. The Austin Chalk is where the returns are right now. It’s 155,000 acres. Then we went to the west, did that drill-to-earn [arrangement] which added 8,000 acres there. Over time, we’ll show more results from the west, extending our position there.

JB: And you’ve grown quite a lot in the Midland Basin.

HV: That’s been the story also in the Midland Basin where we were looking at acquiring. The heart of the Midland Basin was quite competitive to get things. So, we went over to Howard County and looked there, and we classified things by carbonate—porous and non-porous carbonate and the mud rock. Most companies just said, “OK, if there’s carbonate, it’s no good. It’s got to be mud rock.”

But we found that there was a porous carbonate layer also in there that was more productive. When we went into Howard County, there were only 79 wells that were horizontal. We had a lot of vertical control. And now, there’s over 4,000 wells. It was the Viper well in 2017—that’s when we pushed the boundaries to the east quite a bit. It was really into central Howard County. That’s when we knew, and we really bought the acreage out there for two to three intervals, and now there’s as many as eight. And then, more recently, the Woodford-Barnett Permian.

JB: I want to delve a lot more in the Midland but, before we do, I wanted to switch gears and dive into Utah a bit more and, of course, the XCL deal. I think when that was first announced, it probably caught a lot of people off guard that SM was making that move. It’s a new basin for you and a pretty bold move. I wanted to get your take on how it all came to be, especially partnering with Northern Oil and Gas, as well.

HV: Utah is a great asset and, if you’ve been following us, you know that we’re going to figure out where something gives attractive returns and lots of high-quality inventory. If you looked at what we did even back in the Bakken days and South Texas and in the Midland Basin, then Utah fits right there with us. It checked all the boxes for us.

It had a thick hydrocarbon column—thicker than the Delaware Basin even—a 4,000-ft column. There’s lots of oil in place, there’s scale. We knew the transaction would be accretive on all financial metrics. We saw significant upside. Of the 17 intervals that are there, only some of them had been developed, and there’s significantly more potential. The main thing was really high quality and quite low breakeven. It could compete with capital with our portfolio right away. In some other transactions, you look at it and you say, “Well, we can’t put capital to it for a while.” But, in this case, we could do it right away.

It was sized within our balance sheet capability, and that’s where Northern Oil and Gas comes along. We’ve known Northern Oil and Gas. They’ve been a working interest owner in some of our Permian Basin wells, and we understand how they work. So, we said, “OK, it would fit the balance sheet really well with taking on a partner.” Northern is an ideal partner with their business model and coupled with our business model of wanting to operate and being at the cutting edge on the technical side. It basically fits everything for us and could compete right there with Austin Chalk and with the Permian.

JB: Is it fair to say you were keeping your eye on the takeaway situation out there and feeling like the timing was right?

HV: If you talk to people like in 2018, ’19, they’d say, “Hey, it’s a captive market to the refineries in Salt Lake City.” The Salt Lake City refinery capacities are a little over 200,000 bbl/d, but they’re limited in how much waxy crude they can take to about 80,000 bbl/d. Right now, coming out of the Uinta is about 160,000 bbl/d between all the operators. So, the productive capacity three or four years ago started to exceed what the Salt Lake City refineries could take. That’s when rail terminals were put in place that enabled takeaway. The Gulf Coast markets really like it because it helps on the lube cut for them. I’m not a refiner by any means, but my understanding is it’s a higher value product down on the Gulf Coast, and that’s why it’s attractive.

There’s a transportation cost associated with it, but there’s room to optimize over time, and we will figure out where those are over time to optimize on ultimate customers for it. In terms of the rail, there was a lot of coal moving across the west to power plants from the coal mines. That trade has diminished considerably. Now, there’s rail capacity that can ship the waxy crude across to markets. There are at least six markets that it can go to by rail.

JB: Is it pretty easy to overcome that transportation differential at this point?

HV: That differential exists. But the crude is quite easy to transport and loading into rails is no issue. You truck to the rail terminal, and then you rail it out of there. There’s no issue in terms of getting capacity. You obviously have to watch weather conditions and the normal things that you’d have, but there’s plenty of history of railing crude around the U.S.

JB: Can I get you to touch on the different benches out there and how, since the acquisition, you see things evolving? Douglas Creek, Castle Peak, Wasatch, etc.?

HV: We think about it in three parts. There’s the upper cube, the lower cube and then the deep cube. Almost all the development to date has been concentrated on the lower cube. We’ve had over 800 wells by the industry in the lower cube, and only 15 in the upper cube. We just announced four upper cube wells, but we also announced a large number of lower cube wells. I think we had 14 new wells there, and they averaged 1,300 boe/d. For the upper cube, we got four new ones, and they were lower IP, but they looked like shallower decline. It (upper) looks more like the Spraberry in the Permian. If you said the lower cube was like the Wolfcamp, and you said the upper cube was like the Spraberry, you wind up with somewhat lower IPs, but a shallower decline.

The key thing is, it’s all overpressured. There are three sections of it, and there’s 17 intervals overall. Four of them are the ones where all the concentrated development has taken place. So, there’s a lot more potential testing of intervals and delineating to sort out the ultimate inventory that’s out there. We’re feeling quite good about what the potential is there. Our guys are pulling together quite a bit of science data right now to figure out which intervals to go after or when. Predominantly, 2025 is about the lower cube. But you’ll see some delineation in the deep cube and the upper cube this year.

I’m sure all 17 won’t be economic everywhere, but we will have some positive surprises and then some intervals that wouldn’t necessarily work. All we bought it on was for the lower cube. So, the upper cube and deep cube, in our view, is really upside. The high oil content is what we’re really looking for. This year we’re drilling 35 net wells in the Uinta, and we’re completing 50, so we’ll have a lot more data from the areas we’re developing.

When we bought XCL, we also exercised the Altamont [Energy] option. XCL had previously entered into a PSA (production-sharing agreement) with Altamont. They waited for FTC (Federal Trade Commission) approval, received that and, as soon as they received that FTC approval, we exercised the option. Both Northern and SM took our proportionate shares in Altamont also. That’s a considerable amount of acreage just to the north and a little bit east of the XCL position. We feel good about that also.

JB: Because of XCL’s previous activity, you’re a lot more DUC-focused this year, right?

HV: Because they had so many rigs running—and we intend to go to a lower rig count by year end—you’re going to wind up with more DUCs. Plus, they had really large pads. Oil prices were difficult [during the pandemic], so [XCL] got very, very creative in terms of taking cost out of the system. If you look at the operation there, it’s e-frac, large pads, uses residue gas from a plant to drive a gas turbine to generate the power for the e-frac. They put in place a sand mine. They figured out the sand on location was amenable, met all the technical specs to use. Because of the stacked nature of the pay, large pads, close well centers, then the DUC count goes up because of how many wells are on a pad at a given time before you actually frac. You drill quite a few before you frac. So, that helps on the efficiency side.

JB: What else stands out about the Uinta?

HV: I think it’s interesting how overlooked it was, and that’s what made it so attractive to us. Rather than having to compete with a lot of other companies to acquire an asset in a basin that’s really well known where you have to really pay up for it, this we got at a really reasonable cost with massive upside. I would do that every day.

JB: Do you feel like it was kind of perfectly timed in a way because there’s a lot more focus on the Uinta since your deal?

HV: That happened to us also up in Klondike in the Permian where we announced our deal where we were going north beyond where the thermal maturity works, and all of a sudden the subsequent packages really extracted a premium. But we got in there early. If you’re early, you can get it cheaper, but adding onto your position gets more challenging because others recognize what you’ve done. We like being in that position, though.

JB: Obviously, you’ve have grown in the Midland a bit. How is it, in terms of strategy, having three big positions now that are not all equal sized, but they’re all core to SM?

HV: The unifying theme across everything is low breakeven, meaning high returns at mid-cycle prices that can handle low cycles on the commodity price end of things, with a liquids bias. We have considerable dry gas in South Texas that we’re not pursuing at this time. But, in the right environment with sustained higher gas prices, it would be an attractive investment. To date, that hasn’t been the case, but we can see how that could happen in the future. We just don’t know when. We don’t even count our gas in our inventory count, but there’s going to be a day where we can, and that would be coming from South Texas.

JB: On that topic, obviously stable prices aren’t where you want them to be for gas, but they’re still on the upswing and there’s tons of bullishness in terms of the next wave of LNG projects coming on, and everything you hear about data centers and AI. It’s hard to say whether some of that’s overstated or not, but do you feel like it’s a matter of when and not if?

HV: I’m cautiously optimistic that I think there’s a lot of merit in using gas for power generation and all the associated things like data centers that use the power. LNG is transportable to highest priced markets across the globe, and there’s more and more infrastructure being built. That can be beneficial. So, we say, “OK, when is the right time?” You need to have sustained higher gas prices to be confident about it. There’s been much more volatility on the gas side of things. When you see more stability and less volatility, it’s easier to invest. Oil, relatively speaking, has been much less volatile, so that’s been the focus. I remain an optimist on gas. But, for the company today, we’ll continue with the program we have, and then we’ll adjust as we see the potential.

JB: I wanted to pivot back to the Midland Basin. I think it’s fair to say you might be interested in expanding more. I was curious how much you were looking at potential deals before opting for the XCL deal? Was it an either/or situation, and what might be in store for the future of SM in the Midland Basin?

HV: I’ll start at the highest level. We have a large geoscience and engineering team. It is quite integrated between data analysts and the analytical tools, the machine learning. They’ve mapped not just the basins we’re in, but all the basins that are significant, and we really have an idea of what looks attractive to us. In some cases, the land is taken. There’s limited ability to get to the land in several of the basins, but it’s mapped out everywhere. I could tell you the Austin Chalk looks good to us in this whole swath across South Texas. Obviously, we’re not going to share [exactly] where publicly. If those opportunities come up, then we can pursue them. Likewise, in the Permian Basin, our best well ever was a Dean well, and so we mapped everywhere that the Dean looked quite good. When things line up where they come together, then we would pursue a Dean opportunity.

In the case of the Woodford-Barnett, that’s another one where we saw a lot of activity to the north. We looked underneath Sweetie Peck, we had an idea of what the Woodford-Barnett looked like there. Then we said, “OK, we see this play extending up over onto the shelf, and we see players playing it on the shelf.” So, we mapped it out. We then had a buy area for the Woodford-Barnett that we pursued, and then it started getting quite active where you were competing. Then, the cost per acre started to go up, which normally happens. All that we do is underpinned by that technical understanding and gathering of as much data. We engage in enormous numbers of data trades with other operators to expand our database. We use quite a bit of machine learning to automate and to look at what opportunities there are. It really just flags, and then someone can look at things manually. The Uinta was kind of an outcome of that sort of effort where we saw all the elements come together in one place.

JB: How do you feel about the reputation you’ve developed in the Midland Basin for having that pioneering, wildcatting approach in the Dean, Woodford-Barnett, Howard County?

HV: It’s just a testament just to the people we have. They’ve worked for us for a long time, and they understand resource plays in depth. We’ve supported them, given them the resources, and then engaging in the data trades. Basically, we’re making it as easy as possible for them to figure out where these plays could extend. I don’t know how much people understand that from outside our company, but there’s probably some appreciation based on what happens to some of the land after we’ve bought something somewhere. I would say EOG [Resources] is very good also on that sort of approach. That’s all I can say about it, really.

JB: I know you can only say so much, but what else can you say in terms of how you see the future playing out for SM and both the northern and southern Midland parts and the clichéd secret sauce you’ve had?

HV: We have the storyboard, which has all our goals. I’ll just read one of them to you. I won’t say how many there are. It says there’s a certain amount of resource we expect to add each year. That’s not proved reserves, but resource. They need to have a plan for the next inventory opportunities that can be added to the portfolio in the next 24 months. There are very specific goals. I’m not going to say the number, but they need to identify X number of exploration plays and make investment-ready recommendations. That doesn’t mean we’re going to do it. It means they need to have done the work to present it to the executive team. The next one is to recommend six acreage or acquisition targets of sufficient scale. There’s a specific number that they need to come up with. Not that we’d invest in them, but we need to be able to take a look. Then, there’s an existing process to track where there’s success across the industry. Those are the big ones.

Then, the final one is to demonstrate the application of new technologies that enhance returns or inventory. We actually have to do this with the board [of directors]. We go to the board every February, and we go over all the technologies we had tried during the previous year, and then you put like a red light, yellow light, green light. So, if it’s a red light, that means we tried it, and it didn’t work. Yellow, we tried it and we’re still trying to figure out if there’s a benefit or not. Then, green light, it definitely worked. It gave us better results, and we’re continuing to use that in the future.

The board is very driven to making sure that we’re on the cutting edge on technologies for unconventional resource development. It’s pretty much a board mandate that we stay at the cutting edge and we push the boundaries. They understand that everything won’t succeed. It’s not like somebody gets beat up for trying something and failing. We have to try, and then you learn from that. Sometimes you can modify what you do, and then you wind up with a positive result from there.

We show how we do compared to offset operators’ wells, and the range is typically 30% to—in the Woodford-Barnett—50% better than offset operators. It’s because of that technology angle and trying new things. You could have a model of saying, “We’re going to be the low-cost operator,” and that works really well for some. What we’re doing is, we’re trying to get the most value out of the wells, and that takes the technology to sort that out.

JB: Any specific technologies you’re comfortable highlighting, or just anything in terms of delving into lateral lengths, frac intensity, etc.?

HV: There’s the obvious ones. You build your acreage position; you do trades to get contiguous acreage and get long laterals. There’s a lot of modeling you can do numerically with frac modeling, reservoir modeling, spacing decisions that determine the completion design that’s optimal. Spacing and completion design are kind of integrated. Those decisions are really what we do to maximize the incremental rate of return for an additional well in a DSU (drilling spacing unit). We’ll pre-model, let’s say in the Permian, there’s multiple horizons and you put four wells in one, six in another, four in another. Then you add and model a fifth well in one of those intervals. What’s the right return on that incremental investment? And that’s what we really optimize so that we don’t overcapitalize drilling spacing units.

JB: And adding some of the continued learning from industry mistakes in the past?

HV: Yeah, we have all the data trades. You may see what our count of wells in the Permian is, but we have a massive lot more data of others where we’ve traded the data to get exactly what they pumped for completion design, what the lateral length is, how much fluid, how much sand, what the cluster spacing was, what the stage lengths were. We have all that and that’s all integrated into a proprietary machine learning tool that we have.

JB: Is there anything else you can add in terms of the Midland Basin and your future wildcatting and exploration on intervals?

HV: No, just know that we’re going to keep identifying intervals that people overlook or don’t know on their own acreage. We’ll be looking at what can be done there. It is a very competitive basin, obviously. The Midland Basin is the best basin in the Lower 48 and the Delaware Basin is right behind. That’s going to be competitive, but we’ll keep looking for additional intervals and expanding our position where we can.

You cannot rest easy; you have to keep pushing the envelope.

JB: Going bigger picture again, there’s been a ton of consolidation in the last 18 months, two years. Obviously, you’ve played some part in that now. I wanted your thoughts on just how, industrywide, you expect to keep seeing that play out and what role SM might continue to play? And, is there anywhere else you’d look to expand?

HV: We have not constrained our folks at all over the last decade from looking at different basins, but they know it has to compete for capital. They are watching all the significant basins and seeing if there’s an entry that makes sense for us. Obviously, right now we’re focused on integrating the Uinta. A lot of our resources are applied to, how do we get more inventory from those existing basins? But, we’ll continue to look at other basins. I don’t think the Lower 48 is done yet. Finding a new basin, that’s more challenging. But, finding plays within existing basins, I think there’s still room. I was in the Permian in the mid-1990s, and everyone thought it was done for. We were doing CO₂ floods then, and now look at it. We did our first horizontal well in the Midland Basin in 2013, and look where the Midland Basin has gone since then. When we got into Howard County in 2016, we saw two to three intervals, and now you really see eight plus the Woodford-Barnett. Eight in the Woodford and Wolfcamp and Spraberry, and then now Woodford-Barnett. So, we will keep looking.

This is a company that’s very disciplined, knows about technical excellence, and that’s what drives inventory growth. We have long-duration inventory, we have a strong balance sheet, and we have a very motivated, capable team that drives all this. I’m just really fortunate to be a part of the team and what they’ve built over time.