SM Energy Company (SM) Earnings Call Transcript & Summary

Good afternoon, and welcome to day 2 of JPMorgan's 2021 Energy Conference. With us this afternoon, we have SM Energy President and CEO, Herb Vogel. Herb was appointed CEO of SM in November 2020, having previously served as a COO since 2019. He joined SM in 2012 after his retirement from BP, where he most recently served as the President of BP Energy. Herb, I'll turn it over to you for a brief intro on SM, and then we can start the fireside chat.

Okay. Thanks, Zach, and good afternoon or good morning, all of you, depending on where you are in this virtual conference world. And thank you for your interest in SM Energy. Today, I'll show a handful of slides that were posted this morning on our website at sm-energy.com. Please reference Slide 2 as our discussion today includes forward-looking statements. And I'm going to start on Slide 3. So SM Energy is recognized as a premier operator of top-tier oil and gas assets, and our store is really simple. We have some of the best assets in the Midland Basin, and that's based on high revenue per BOE and among the lowest breakeven prices in the basin. In South Texas, we hold a large acreage position that offers a diversity of commodity mix, and substantial upside value potential that I'm going to cover in a couple of minutes. I think most of you know our story as we've recently participated in a number of investor conferences. So today, rather than walk through that entire deck, I'm going to skip ahead and focus on the Austin Chalk in South Texas, where this morning, we announced several new well results. We're really excited about them. The new wells look terrific, and I'd like to cover 3 key points today. Our confidence in the Austin Chalk play with new -- more new wells supporting repeatability and predictability of a full scale development. Our sizable acreage position, which supports an inventory that we believe is around 400 wells in the Austin Chalk. And finally, the value proposition the grill. It's competitive with the Permian. So now I'll skip ahead to Slide 15. So just jumping right to the Austin Chalk. This will give us some more time for Q&A. So we're often asked, what gives us the confidence in the Austin Chalk? Well, first, it's the data that we have. Our geoscience team has been working this area for years. We have a lot of data from around 600 penetrations through the Austin Chalk from developing the deeper Eagle Ford over the past 12 years. That database allows us to accurately map the play, and we took about 500 feet of core in the Austin Chalk in 2019 and the findings there, the actual rock data really jump-started our effort and helped us optimize our landing zone, which is critical here. We now also have expensive data from '15, producing Austin Chalk wells on our acreage. Since we started this effort with our first horizontal Austin Chalk around 2018, we further refined our landing zones, our completions and even lateral lengths seeking the confirmation through delineation over a broad area. You can see the locations of our existing and planned 2021 completions on the map to the lower right on this slide. So the second thing is predictability. This is supported by the results of our wells to date. We have 155,000 net acres in South Texas, where delineation and development to date has proven that the Austin Chalk can generate high returns across all of the acreage that we've tested to date. We have successful wells in the northern, southern and eastern areas, with 7 of our 15 Austin Chalk wells on production for a year or longer. So we understand and connectively forecast the initial decline rates on the wells. So our most recent wells announced today are not only outstanding performers, but they really reflect what we expected from the targeted landing zones, including the production rates and the commodity mix. So we're able to accurately forecast the performance of these wells, and that's critical in a resource play. So we've demonstrated a variable commodity mix across our acreage, which is very predictable. There's higher oil content in the north, strong NGL productivity to the east and higher gas content to the south. We estimate our inventory of Austin Chalk wells at around 400 locations, and that assumes development with long laterals, an average lateral length of around 11,000 feet. So I'm just going to point to that map on the lower right of the Slide 15. And our new eastern wells are in red and our blue -- in blue are new JV wells. So remember the locations there, as I turn to Slide 16. These most recent well results really bolster our confidence in the value of the play. Among the eastern wells, let me point out, in particular, the Galvan 914H well, which we announced this morning. This well delivered an average 30-day peak rate of over 4,000 barrels equivalent a day, of which 1,100 barrels per day are condensate. That is our highest peak rate Austin Chalk well completed to date and the second best on a per lateral foot basis. The 3 new eastern area wells averaged 3,300 barrels equivalent a day for 30-day peak rates. And these wells were completed, offsetting an earlier Austin Chalk well. So all 4 are at 1,250 foot spacing and are located directly above several Eagle Ford wells. Turning to JV wells, those that were in blue on the map, are drilled in the southern area. They were co-developed with the Eagle Ford at 625-foot spacing or 1,250-foot spacing in zone. Those JV and Austin Chalk wells are estimated to have an average return around 85%. So we like to say that this is not your father's Austin Chalk. And when I say that, I'm thinking East Texas in 1980s with vertical wells and natural fracture play. This -- we're working on here is a new play extension to the west into better rock, controlled by great matrix permeability and free from extensive natural fractures. What we are delineating and now developing is the same play that EOG is highlighting about 15 miles to the south as their Dorado play. We're just in an area with high liquids content instead of the dry gas that they're developing there. The key to success here is gathering the data and doing the technical work to identify the optimal landing zone in a thick Austin Chalk section. So now I'm going to turn to Slide 17. The value proposition here is driven by the well economics. We've seen outstanding well productivity, which, when combined with high liquids content and capital efficiencies from long laterals and existing infrastructure, leads to really a step change in the value of our South Texas asset. Let me point out just a few metrics. The economics are much improved over our legacy Eagle Ford, just period. Austin Chalk liquids content averages around 50% to 80%. The estimated 10% IRR breakeven oil price for these wells is $12 to $28 per barrel, which is just outstanding, and that assumes $2.50 gas. Comparing revenue for an Austin Chalk versus an Eagle Ford well at $50 oil and $2.50 gas, an Austin Chalk well delivers on average about 60% more revenue and even more on the northern acreage, which is oilier. In addition, starting last October, our oil realization increased $9 to $10 per barrel as a result of a legacy contract rolling up. Costs are substantially lower. LOE per BOE is lower than our South Texas average just given newer wells. But then transportation is substantially lower per BOE due to less gas and commodities. Gas is where the cost related accrues. Further, cash possible benefit starting next month from a $0.25 per Mcf step-down in gas gathering costs. So that's July of 2022 -- 2021 and another $0.35 step-down in transportation costs in mid 2023, and that's from long-haul transport. So capital efficiency is optimized with longer lateral, 11,000-plus foot wells. Combine this with a higher revenue and lower production cost per BOE, and we realize strong margins and very high returns. We are estimating our 2021 Austin Chalk program wells to have an IRR greater than 100% and to reach payout in about a year. Bottom line, the margin is 3x higher than legacy high gas content, South Texas wells, calculated using $50 oil and $2.50 gas. That is critically important to value here. The breakeven oil price of $12 to $28 per barrel means the Austin Chalk wells are competitive on our Midland Basin assets, which we know are some of the best in the Permian Basin. So we've really demonstrated our confidence in the Austin Chalk this year with the program that includes drilling some 30 Austin Chalk wells and completing around 20 of them. So before I turn it over to questions and Zach, let's flip back to the balance sheet on Slide 9. Just like to make a couple of comments here. Our key objectives for this year and next are to generate substantial free cash flow that will be used for debt reduction, targeting around 1.5x leverage debt to EBITDAX at year-end 2022. We have a great balance sheet and took steps last month to make it even stronger by terming out some greater and near-term maturities. We added $400 million of 6.5% bonds due 2028 to fund paying off the 2022 maturities and reducing to 2024. This indicates no change to our plans to reduce debt. It just took a little risk off the table on near-term maturities. We have plenty of prepayable debt to attack as the free cash flow is generated, including the 10% second liens, which become callable next year. Finally, I will also direct you to Slide 18 and 19. When we talk about being a premier operator, that includes ESG performance, and here, you'll see that we are in the best quartile among our peers. So to sum up, we have a simple story. We've got great assets. We've got a great team. The new Austin Chalk results continue to support real value creation that is yet to be recognized by The Street. And we have a very clear and visible plan to drive big growth and free cash flow and transport enterprise value to the equity holders. With that, I'll turn it back over to you, Zach.

Thank you for that presentation, Herb. You talked a lot about the Austin Chalk there. So maybe we'll start there. How should we think about the future split of development in South Texas versus in the Midland? I think this year, you're drawing down some DUCs in the Midland Basin and building a few DUCs in South Texas. Is that a sign that it will be a more evenly split capital program in '22?

That's a great question, Zach. The way we look at it is the returns from both assets are similar, and we have optionality on the commodity mix. We have -- we can do dry gas all the way to very liquids-rich Austin Chalk. When we model this, we will model capital allocation of 70-30 or 60-40 or 80-20. And at current commodity prices, it doesn't make much difference in reaching our financial objectives. So we have optionality there. And as we get into the planning period at the end of the year, we'll look at how to allocate that capital to optimize the cash flow, and we really do not have like target production. We have target financial objectives at the end of the year out, 2 years out, 3 years out from our current budget year. So that's how we really look at it. So we've got the luxury of having similar returns from all our assets.

Got it. And you mentioned 1,250 foot spacing in the Austin Chalk. Is that what your current inventory at those 400 locations you talked about is based on?

No. It varies across our acreage position. We have, as I mentioned, oilier in the North and West and gas to the very South, [ solo very ]. And I did mention that JV was 1,250 in the Chalk and 625-foot plan due to include the Eagle Ford. So we're going to have a mix. This next tranche of wells that we're working on will be testing other concepts around spacing. And as those prove up, that's when we'll lock in more on those 400 wells.

Can you give us any color on how tight you're testing spacing in the Chalk?

So right now, they're in that -- well, the current ones, the farthest we've gone down is 1,250. We've got some that are slated for the 1,000 and a little less than 1,000 foot spacing.

Got it. That's good color. One investor question that's specific to the Chalk, asking about the oil mix on those wells. Of the oil mix, how much of that is black oil versus condensate? And if there is condensate, how much, if any, is retrograde?

Okay. So that's a real localized question for the different areas. So on the very northwest end, we're in a volatile oil. That's what PVT test will tell you, and then it transitions through the condensate. As you get more to the South and East, the API gravities are in the low 50s. We've got some high, high 40s on the very northwest. And then the highest gravity, we'll see is in the high 50s so far. We haven't gone all the way to the south, where it could be there. But the -- I would say the PVT behavior here is quite predictable. And so we've had some wells flowing for more than 2 years. And like I mentioned, 7 have been flowing over a year. So we're quite pleased with the way the condensate rates are holding up.

Got it. That's helpful color. Maybe I'll shift more towards the broader capital allocation strategy at the company. You all talked about spending less than 75% of cash flow in 2022 plus. Can you just talk about why that's the right investment rate? And is there an oil price where you would shift that investment rate up or down?

Right. Zach, so when we showed those -- that was the first time we laid out a 5-year plan, and that was in February. We said even at that strip in January, which was considerably lower than it is now. And we just ran that out, and we said, okay, you like -- for capital efficiency, you like to keep activity level pretty flat. So we just ran a flat activity level case from the '22 level out for the subsequent years. And what we saw is low growth, low single-digit growth with that sort of activity level, and that was the reinvestment rate now. With commodity prices where they are, obviously, the reinvestment rate to achieve those same results could be quite a bit lower. So we will optimize that over time. But what we said is, what's really important to us is for this next year, 1.5 years, get that leverage down, if we can get to the 1.5x sooner, the better with high commodity prices and demonstrate the value in the Austin Chalk. Those are the objectives, and then we have lots of options on what to do from a cash flow perspective in the out years.

Got it. And then another investor question here kind of in that same vein, but how are you thinking about 2022 production growth with oil above $70 currently, but also with OPEC still with a significant amount of barrels on the sidelines?

Right. So when we think about '22, we're still focused on those same objectives of getting that leverage down to 1.5x. So we're not going to do anything that crank up our capital program or something like that. We'll have to watch inflation, obviously. So -- and you don't know what OPEC will do. We're going to continue our hedging program, but we're going to target a lower absolute level of hedges, we were at a high level from historical leverage levels. Now that we're at lower leverage levels, we'll be targeting more at the 50% type of level on our hedges. And those are layered on methodically. It's been a very successful program for us over the past decade. So that's how we look at it. It's meet those objectives and then look at the options a lot before you run.

Got it. That makes sense. One more investor question also on the Austin Chalk. Were the new eastern wells landed within a different zone within the Chalk and when will you have your next wells in the northwestern portion of the play online?

That's a great and very observant question. So I'll say there are 2 of the original landing zone and 2 in a better landing zone. So we have on our program this year, we have a mix of some DUCs that were in an older landing zone, and then we've got some in the newer landing zone. And we really optimize that because that's really what we've shown is as critical to getting high returns. And we can even get better if we can really optimize that. So that's 2 and 2. So of those 3, 1 is the new landing zone, 2 are the older landing zone. And then the other 1 was the parent well right next door that started producing last year.

Got it. And then the follow-up there was, when will the next wells be online in the northwestern part of the play?

So on the northwest side, they'll just be later in the year. We do have 1 currently producing at the very east end right now. It's just been on for a couple of weeks. And we're real pleased with what we're seeing there also.

Got it. Maybe shifting over to the Midland for one. In 1Q, your cost per foot take just a little bit higher at $520 per lateral foot versus 4Q, where I think you were sub-$500. Can you talk about what drove those costs higher and how costs are currently trending? And then have you seen any signs of cost inflation, kind of what are you seeing in the field now?

Right. Okay. That -- so first of all, yes, we've been using higher sand loading in our most recent Midland Basin completions. So we upped from that around 1,800, 1,900 pounds per foot to the 2,500 plus, almost 2,800 pound per foot level. So that -- there's a slight increase in cost, but we see the incremental costs relatively low, but the returns on net incremental cost extremely high. So we are testing that now. We are quite confident in how that will look. And that's integrated into all our planning for the year and we put out that number of $520 per foot based on that assumption on that sand loading. In terms of inflation, so in the first quarter, we were really pleased to see not much. The 2 areas that we did see inflation are diesel costs, obviously, for fueling our frac pumps and our rigs. And then steel costs, which are relatively low percentage cost of our wells, but the inflation was there. Now I'd say we're seeing some trucking inflation. We're seeing some potential labor inflation. And we're watching closely what's happening on the pumping services side. You're starting to see ESG differentiation where there's a tighter supply for low emissions, be it a dual fuel or e-frac and lower cost per higher emissions and that have been striving for reducing their combustion emissions. So that's driving that. In terms of SM itself, we have our sand cost locked in from a nearby sand mine that we were the anchor customer of. So we don't expect to see much inflation there, and we typically do our rigs a year at a time. And so they feather off over time. So we have some insulation. We've also advanced some activity into the second quarter. So that avoided some inflation late in the year.

Got it. Maybe shifting gears a little bit to the M&A and A&D outlook for SM. We've seen a number of consolidating transactions within the Permian and within other basins. What role do you see SM playing within the broader consolidation within the industry? And how do you see that trending over time?

Right. Well, Zach, you know there's been a lot of consolidation, a lot of our neighbors have consolidated, and we see that trend continuing. We think it makes sense. There's obvious G&A reductions. And in some cases, there's synergies where it really makes sense, especially if they're acreage synergies, and we think we will do what's best for our shareholders. The way we look at it, we don't have the Austin Chalk fully reflecting in our share price yet. And we think our assets would be extremely attractive to an acquirer, just the quality of them. There's a lot of running room of high return that doesn't diminish over time in the inventory. So we want to get the Austin Chalk value, one, get the balance sheet where it's in better shape, and then we become even more attractive potentially. In terms of our ability to either do an MOE or take out somebody smaller, we really look closely at the quality assets. And if the quality assets can measure up in our stack, that's great, and that becomes attractive to us. What we don't want to do is look at acquiring somebody that we can't drill their inventory visits, subpar compared to ours. And that would push their capital program out, and then it's difficult to pay the value. So that's how we look at. But we think consolidation will continue, and we'll just continue target our objectives around Austin Chalk value and balance sheet improvement and see where things go from there.

Got it. Another question -- investor question here. Do you have -- your net leverage target, is that based on last 12 months EBITDA because higher oil prices are obviously going to elevate your EBITDA, do you have an absolute debt target in the numerator of that calculation?

Yes. I'd say, exactly what we've done there is we really laid out that plan in January to get below 2x by end of '22. Commodity price tailwinds, as I said, well, we can make 1.5 by end of '22. So we really were planning around that. As we get into the planning for 2022, we'll have more Austin Chalk well results, we'll know how to model going forward there. We'll continue to execute on our Permian program, and then we'll decide what to do. But we don't have an absolute debt level target in mind. It was really getting the leverage to that point by end of '22 because that can automatically convert EV over to shareholder value.

Got it. And while you're still going after your debt targets, a number of E&Ps in the industry have started cash return programs once they reach those debt targets. How do you think about that longer-term dividends, buybacks, variable dividends? Is that something you would consider? And when would you consider that, how soon after reaching those debt targets?

Right. So Zach, we look at that we want to get to that point first, and then we'll have lots of options. The key thing is generating that free cash flow, and that's what we want to do. So we'll have options as we get to the back half of '22, we'll be able to say, okay, these are the free cash flow projections at the commodity price environment at that time. And we'll look forward and say, okay, this is what makes sense for our shareholders. That's how I look at it. So we don't want to presuppose, get too far over our skis in -- on what we'll do there. So what we're going to stay the course with where we are for '21 and '22 for now.

Got it. And then you talked about this a little earlier. You've drawn down some DUCs in the Midland and building up some DUCs in the South Texas this year. How will those -- can you give us some color on how those DUCs contribute to the '21 program? And maybe what's a normal level of DUCs to have in the portfolio?

Yes. I'd say we're not too far from a normal level of DUCs, just based on the logistics. Larger pad sizes lead to higher DUC counts. It's really a balanced program. We don't really target DUC per se. It's just outgrowth of that whole free cash flow planning process that we're doing and the leverage reduction. So the -- and the DUC drawdown can very -- if you have a pad of 6 wells coming online on one side of the end of the year, we spent the capital so they start up January 1 or December 31, and they'll make a difference of 6 or if you have 2 pads that are 6 wells each, that will be 12. So you can see quite a swing around there. So we don't really -- there's no real DUC objective from our part. It's really driving towards the most -- the way we can be most capital-efficient is to have a steady program. So a steady number of rigs, steady number of frac spreads, that's [ when we have ] real dividends. And you'll see on our execution statistics, we just get faster and faster when we're able to do that. So that's really from a capital efficiency standpoint, that's the way I like to run the company.

That makes a lot of sense there. We're running up on the end of our time here, but maybe I'll try to squeeze in a couple of more. One more investor question, getting berry in the weeds on the Austin Chalk, which well in the new landing -- which of the wells of the 3 is in the new landing zone?

The 914H and the 910H. The 910 has been on for a bit.

Got it. And then I guess I'll just close with one more. You talked a little bit about this in your presentation. But can you just talk about what SM is doing from an ESG perspective as that's been front of mind for investors?

Yes. Let me start first. We've really upped our disclosure and our transparency. We've done SASB, TCFD, CDP, so that we build out the surveys, and we continue to become more and more transparent on those metrics. We've become more transparent on the social side. You'll see on Slide 19, more there. And we're going to continue to do that. Fundamentally, as part of being a premier operator, we view this as good business, capturing the gas, not flaring it and doing what we can. We've done physical things like interconnecting between third-party gas plants so that if one goes down, we can direct to the other one rather than flare. That makes a big difference. We're looking at what we can do to reduce our combustion numbers, decreasing diesel usage where we can. So we're basically on every element, but fundamentally, our whole team is motivated. Our LTIP has a high percentage of ESG metrics that include safety, spills and greenhouse gas emissions. And our STIPs, our short-term incentive program -- the bonus program annually is the same way were -- as those same metrics. So people are incentivized, and what's great is to see the new ideas coming up all the time that have reduced our emissions. And you can see on Slide 18, those that were top quartile by those metrics compared to our peers. And it's just been a focus -- it's been in our comp program for quite a while. So it's not new for us. But Zach, that is important to us.

Got it. Thanks for that color. We've run up on the end of our time here. Herb, thank you and SM for participating today. And thanks to all the investors that were on the line with us.

Okay. Thanks for having us here, Zach.