SM Energy Co (SM) 2022 Q1 法說會逐字稿

Good day. Thank you for standing by, and welcome to the SM Energy First Quarter 2022 Financial and Operating Results Q&A (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions) I would now like to hand the conference over to Jennifer Samuels, Vice President of Investor Relations. Thank you. Please go ahead.

Good morning, and thank you for joining us for our first quarter 2022 Q&A call. To answer your questions today, we have President and CEO, Herb Vogel and CFO, Wade Pursell.

Before we get started, our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to Slide 2 of the accompanying slide deck, Page 4 of the accompanying earnings release and the Risk Factors section of our most recently filed 10-K and 10-Q, which describe risks associated with forward-looking statements that could cause actual results to differ. We may also refer to non-GAAP measures.

Please see the slide deck appendix and earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures.

Also look this morning for our first quarter 10-Q, which we have filed. And with that, I will turn it back to the operator, Blue to take your questions.

(Operator Instructions) The first question comes from the line of Leo Mariani from KeyBanc.

Just wanted to touch base with you here on CapEx. So I just wanted to get a sense in terms of the year here in '22. The second quarter CapEx really going to be the peak. And is there a noticeable drop off in the fourth quarter, perhaps there's a frac holiday or something like that? And then just additionally, is the frac holiday, if that is the case in the fourth quarter. Is that something that can still be feasible in this kind of tighter service environment or might you have to keep crews on?

Thanks, Leo. This is Herb. On CapEx, first, you probably saw in the first quarter that we were underspent by about $20 million, we really just spent some timing, and we've moved that into the second quarter. The peak activities really 2Q and 3Q, and so that leads to more production in 3Q and 4Q. We really like to keep crews running consistently, if at all possible, because we get much better capital efficiency that way. So we'll do what we can to just line things out with steady activity through the year. That's really the way it works.

Okay. And then just also wanted to ask about return of capital. Just kind of reading some of the prepared comments of the transcript, it sounds like you'll believe you'll hit your debt metrics in the fourth quarter. So it sounds like maybe the Board or whatever will be in a position in the fourth quarter to maybe make decision on a return of capital and that will be something that investors will receive in '23. Just wanted to make sure I kind of understood the timing and mechanics there.

Yes. No, you heard the comments right, Leo. I mean we've been pretty clear about our targets and what we're approaching really quickly, 1x leverage, but also on absolute debt down to $1 billion. And if things stay the way they are right now, commodity prices, et cetera, that should occur sometime in the fourth quarter, as you indicated. And that would be the time that we would start looking at a potential return of cash to shareholders. And too early to talk about what that might look like, but it would be something that we feel very confident in being sustainable. And then the method would be based on things that we would analyze at that time.

Your next question comes from the line of Zach Parham from JPMorgan.

I guess one, just kind of based on production trajectory for the rest of the year. With your guide, 2Q will be the third straight quarter of declining oil volumes after a big ramp in the back half of '21. Can you talk a little bit about the trajectory of oil production in the back half of the year into '23?

Yes. Zack, this is Herb. There's some history there with how much we ramped up in '21, in 2Q and 3Q following the weather event in Texas. So that's kind of changed how we ended '21 and how we started '22 with relatively few completions at that time. So as we step through '22 and our activity level is pretty flat here, and we wind up with more and more completions coming on. That's what leads to great production in 3Q and 4Q. And then in 4Q, we have those 4 Permian pads we've talked about before. So those don't come online. That's 20 wells that don't come online until early '23. So it's really difficult to look at the quarterly cadence type of numbers for us when we have those sorts of things going on. We just see it year-over-year. We're really focused on that planned increase and maximize free cash flow over a 2- to 3-year period.

And that's how the plan is designed. That's pretty much the way you should look at. So when you see year-over-year low single-digit production growth and -- but generating a lot of free cash flow.

Got it. And just one on the Eagle Ford. In the prepared remarks, you talked about completing some Eagle Ford wells in 1Q and then 3 more Eagle Ford completions at 2Q. Can you talk about what drove the decision to drill some Eagle Ford wells versus spending that capital in the Austin Chalk and kind of how you think about that drilling Eagle Ford wells going forward?

Yes. So a couple of things. So there were 2 of them that we talked about where we talked about the payout already delivered. And those were tied together with 7 Austin Chalk wells. So they were right in that development. So it made sense to pretty much stagger those in. The newest to are DUCs that we've had sitting around for a while. We have some other Eagle Ford DUCs, so it's very capital efficient. Commodity prices are right. It made a lot of sense to do those. But those were in our original plan for the year. I think we talked about 38 completions for the year. And I believe around 30 of those are Austin Chalk, maybe 32 and 6 to 8 are Eagle Ford. So that was the original plan, but very capital efficient when we can get to the DUCs.

Your next question comes from the line of Michael Scialla from Stifel.

Just looking at Slide 6, it shows your -- in your slide deck shows your capital efficiencies, those are kind of among the best in the industry over the last 5 years. Just wanted to see if you could provide any update on current well costs. I think it's been a while since you put anything out on or current well costs are.

Mike, thanks for that question. So we're still running off of contracts in the first quarter that we've had for a while. So -- and that goes for 2Q, largely baked in costs that we had contracted a while ago. So that really helps us on the capital efficiency side. The others, we continue to use the same drilling and completion service providers. So what happens is we actually wind up drilling faster than expected. So when you see things happening with us, it's really just things happen faster, and we don't bake that in our budget process. But every year, we think we're at peak efficiency and then we do better. So that's really just a really experienced team with a sustained commitment to those service providers.

Sounds good. Is it fair to say you're still in the kind of the sub $700 per foot range with those given those contracts and the efficiencies that you're seeing?

Yes, definitely.

Sounds good. And then One of your largest competitors in the Midland Basin just recently mentioned they're having issues getting sand. I want to see if you guys are having any problems with that? And any plans to address that if it does become an issue for you?

No, Mike, we're really fortunate there. We were quite strategic in getting sand supply committed in 2017 being the anchor customer of a new sand mine in Lamesa, and we also use their logistics arm. So we have not had any sand availability problems at all, and we're really pleased with that relationship. It continues to deliver, and we -- as our sand-mine closer to our operations. So we cut down on the last mile logistics costs.

(Operator Instructions) We have a follow-up question from Michael Scialla from Stifel.

Yes. I guess keep going here. I know it's a continuous process when you're working on your well design. It sounds like you're pretty far along with the Midland now. Can you say where you are in terms of the Chalk maybe, in terms of innings relative to where you are in the Midland and the completion design?

Well, Mike, that's a great question. So we are in the -- you're probably aware, we -- last quarter, we talked about that additional $18 million in data gathering, which will help us optimize the completion design. And we're in the midst of gathering that data. In some cases, we've got some additional data. So we're hard at it. We have not implemented anything really differently so far. There's one minor variation, but that's -- there's still lots to come. The interesting thing, though, is that we've noticed now that there's 11 operators active in Webb County in the Austin Chalk, 5 of them are public and 6 are private. So our well results have definitely been noticed by industry. So activity is picking up out there.

Anything you can say in terms of have you seen any other wells being drilled and plans to share data with any of these? Or any thoughts around how you approach the competition?

Yes. So Mike, we do engage with a few of the other participants on data trades and then some of them are other ones are quite new. And then we're in the oilier part. So there's not -- so we're not doing that much with the dry gas folks down there. But it's encouraging to see, and I'm looking forward to seeing what the well results are looking like as they sort out the right landing zone. Some of the early wells were probably not in the optimal landing zone and now you see people moving towards the better landing zones.

Got it. And then I know you were asked about the Eagle Ford earlier. I just wanted to follow up on that. It looks like those wells are -- you'd mentioned they're going to pay out in less than 6 months. Is that strictly attributable to higher prices? Or did you do anything different with the completion design of the Eagle Ford relative to what you were doing previously?

Well, our prices definitely helped. There's -- the completion design is pretty much the same that we've been running in the Eagle Ford. There were a couple that were drilled in 2019, and those are targeting great landing zone and they're decently long laterals and that helps also. But we do feel like we have a great Eagle Ford option out there in our -- that's really not much in our proved reserves, but is out there in our inventory. So if there is a sustained high gas price out there, we have quite a bit of inventory to go after.

Got it. And then I guess just one last one in terms of inventory. Anything different on the 400 locations that you've talked about in the Chalk. I know you've got 40 wells now that you've delineated the play with, still looking at that 400 locations as kind of the best number for the inventory there? Or any update there?

Yes, Mike, we're sticking with 400 now. We'll see what more we can do, but 400 is quite a bit of runway in front of us and we'll work to optimize that over time. So -- but it's just a great resource base out there.

Your next question comes from the line of Scott Hanold from RBC Capital Markets.

I'm just kind of curious, as you start looking into 2023, there's a lot of, obviously, concerns about Permian gas takeaway. And I know your production in the Permian typically is a little bit more oily. But can you remind us of how you're positioned there if you've got firm takeaway that's going to be ample and not seeing any issues? And also in the Eagle Ford, given the, I guess, larger kind of gas component there, is there any -- can you just remind us of what the gas takeaway capacity for you guys is in the Eagle Ford? And how you guys price that? Are you seeing some pretty good differentials to be able to get into the LNG corridor or other places?

Yes. Thanks, Scott. So let's go on the Permian gas takeaway. So kind of the perception last quarter was that, we see quite a bit of tightness in the takeaway in fourth quarter of '23. Since that time, Kinder has gone out there and said they'd be able to do compression expansions and those would be online by fourth quarter of '23. That really pushes things out where you wouldn't be oversupplied until the back half of '24.

We're not really changing our plans at all for any of this because on the volume risk side, most of our purchasers hold firm capacity or they're selling the firm markets. So we don't expect any production curtailments there. That's on the volume risk side. And then on the price risk side, if things do start getting tight, we put basis hedges in place. You'll see in our appendix. We've got base hedges in place through '25. So that mitigates the risk on pricing, if there is a low out of some sort.

But overall, it's going to depend on supply and demand out of the Permian. If people really crank up production when that shortfall might occur. But it's encouraging to see the midstreamers stepping up and making sure that we can deliver the gas, which allows the oil to flow. So that's the Permian.

On the Eagle Ford, you're probably aware that there was a lot of gas production out of the Eagle Ford, mid-decades of 2014, '15. So there's a lot of spare takeaway capacity. And what we see and have baked in for July '23 and beyond is some of our old legacy contracts that -- we're at higher takeaway costs, higher takeaway basic costs, they'll drop by about $0.35 an Mcf, and there's plenty of capacity.

As to the LNG uplift, we are really just going to be going with the marker. So if LNG pulls up, Houston Ship Channel or Tennessee Zone 0 or Hub, we would see it brought in that way. We wouldn't see it directly where we could access an international arm on the LNG side.

Okay. And back to the Permian, can you tell us on the purchasers that take away your gas there, you said they have firm capacity. Can you say where that capacity is on there? Is there like ample room on those lines right now? Or is that -- do you have -- as you look at your projections, I guess, through '24, I mean, do you have that pretty much locked in?

So what we do is we sell the purchaser of the well head. To the purchaser, we only will sell to parties who represent that they have firm capacity on line or are selling into a firm market, like a local market. So that's how we mitigate the volume risk. We won't sell to somebody who doesn't have any capacity at all. So because they have that capacity, so let's say they have 20% of one of the pipelines and 15% of another volume of capacity. That's where our MCF will flow.

Got it. Okay. And then my follow-up question is, as you start -- and I think this quarter, you guys didn't book a valuation allowance on taxes. Can you remind us your positioning on cash taxes and at this commodity price drip when that could occur?

Scott, it's Wade. Good question. I would assume that things stay the way they are currently with the strip and our -- kind of our steady activity profile that we would probably begin paying some cash taxes later this year in the kind of 10 to mid-teens million area. So not significant, obviously, on a go-forward basis, and this is very round forecasting.

But I see something for us that getting up to kind of peaking in an area of $100 million to $150 million a year. And again, that assumes kind of a strip-type price. So obviously, that assumes a significant amount of free cash flow offsetting that. But that's kind of where things could be added, assuming there's no big changes.

Yes. And just out of curiosity, what is that like $100 million to $150 million imply on an effective cash tax rate on pretax income.

Yes, it's certainly well south of the statutory rate, the 20% area. It's well...

Here we're talking like 10%, 15% somewhere around there or around 10%.

Yes, very round numbers, probably somewhere in the half of the statutory tax rate area, but that's very round numbers. But that's simply because of the assumption that we continue with a steady capital program, all of the tax rules stay the way they are, IDCs, et cetera. That -- as long as those things are in place, that's what's going to happen with respect to our rate effective rates, if you will.

(Operator Instructions) There are no further questions at this time. I would now like to turn the conference back to Herb Vogel for closing remarks.

All right. Well, thank you all for your interest in SM Energy. And since I've got the time and I just thought it, f you're asking why invest in SM Energy now, just consider these key attributes.

First, we're producing top-tier, low breakeven assets in 2 great basins, #1 and #4 in the country. We're able to generate significant free cash flow. We are rapidly paying off debt and really moving EV to equity. We're definitely a premier operator pushing technical advancements to add value, and we're enjoying an intrinsic increase in NAV or EV from confirmation of the Austin Chalk. So thanks again for your interest.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.