Good day. Thank you for standing by and welcome to the SM Energy First Quarter 2022 Financial and Operating Results Q&A. At this time, all participants are in a listen-only mode. Please be advised that today's conference is being recorded. I would now like to hand the conference over to Jennifer Samuels, VP 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 our 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 to take your questions.

The first question comes from the line of Leo Mariani from KeyBanc.

Just wanted to touch base with you here on CapEx. So just wanted to get the sense in terms of the year here in '22. Is 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 a 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, and 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 under spend by about 20 million. And we really just – that's just timing, and we moved that into the second quarter. The peak activities relate to Q2 and Q3, and so that leads to more production in Q3 and Q4. 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 throughout the year. That's really the way it works.

And I just also wanted to ask about return of capital. Just kind of reading some of the prepared comments in the transcript, it sounds like you all 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 a 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.

Yeah, no, you heard the comments, right, Leo. I mean, we've been pretty clear about our targets, and we're approaching really quickly one times leverage, but also want to absolutely get down to $1 billion. And if things stay the way they are right now with commodity prices, etc., 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 it's too early to talk about what that might look like, but it would be something that we feel very confident in being sustainable.

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 guidance, Q2 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 and into '23?

Yeah, Zach, this is Herb. There's some history there with how much we ramped up in '21 in Q2 and Q3 following the weather event in Texas. So that 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 levels are pretty flat here, and we wind up with more and more completions coming on, that's what leads to great production in Q3 and Q4. And then in Q4, we have those four Permian tabs 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 plan to increase and maximize free cash flow over a two to three year period. And that's how the plan is designed. That's pretty much the way you should look at it, the way you see it, year-over-year low-single-digit production growth, but generating a lot of free cash flow.

And just one on the Eagle Ford. In the prepared remarks, you talked about completing some Eagle Ford wells in Q1 and then three more Eagle Ford completions in Q2. 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?

So a couple of things. So there were two of them that we talked about where we would talk about the payouts already delivered. And those were tied together with seven Austin Chalk wells. So they were right in that development. So it made sense to stagger those in. The newest to our 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, 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.

Looking at Slide 6, it indicates that your capital efficiencies are among the best in the industry over the past five years. Could you provide an update on current well costs? It has been some time since you shared any information on well costs.

So, we're still running off a contract in the first quarter that we've had for a while, so. And that goes for Q2 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 within, it's really just things happen faster, and we don't make that in our budget process. But every year we think we're at peak efficiency then we do better. So that's really just a really experienced team with sustained commitment to those service providers.

So is it fair to say you're still in the sub $700 per foot range given those contracts and the efficiencies that you're seeing?

Yes, definitely.

And then one of your largest competitors in the Midland basin just recently mentioned they're having issues getting sand. Wanted 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 that we were quite strategic in getting sand supply committed in 2017 by being the anchor customer of a new sand mine in Lamesa. 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 as I said, we found mines closer to our operations, so we cut down on the last mile logistics costs.

You have a follow-up question from Michael Scialla from Stifel.

I know it's a continuous process when you're working on your well design. It sounds like you're pretty far along within Midland now. Can you see where you are in terms of the Chalk? Maybe in terms of innings relative to where you are in the Midland in the completion design?

Mike, that's a great question. So we are in the – you're probably aware, 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 are 11 operators active in Webb County in the Austin Chalk; five of them are public and six are private. So our well results have definitely been noticed by the industry. So activity is picking up out there.

Anything you can say in terms of the – are you seeing any other wells being drilled and plans? Do you share data with any of these or any thoughts around how you approach the competition?

Yeah. So Mike, we do engage with a few of the other participants on data trade, and then some of them are quite new. And then we're in the oilier part. 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.

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 mentioned there once, is that strictly attributable to higher prices or did you do anything different with the completion design at Eagle Ford relative to what you were doing previously?

Well, our prices have definitely helped there; 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 a 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 that’s really not much in our approved reserves, but it's out there in our inventory. So if there is a sustained high gas price out there, we have quite a bit of inventory to come after.

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 target? 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. Any update there?

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. And as you started looking into 2023, there are obviously concerns about Permian gas takeaway, and 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 these issues? And also in the Eagle Ford, given the larger kind of gas component there, 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?

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 Q4 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 Q4 of '23. That really pushes things out where you wouldn't be experiencing oversight supply 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 in the fair markets. So we don't expect any production contaminants there. That's on the volume side. And then on the price risk side, things do start getting tight. We've 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 flow out of some sort. But overall, it's going to depend on supply and demand. Out at the Permian, people really crank up production when that shortfall might occur. But it's encouraging to see that midstream is stepping up and making sure that we can deliver the gas, which allows the oil to flow.

Okay. And back to the Permian, can you tell us 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 ample room on those lines right now, or do you have, as you look at your projections, I guess through '24, do you have that pretty much locked in?

So what we do is we sell to the purchaser at the wellhead, and the purchaser only will sell to parties who represent that they have firm capacity on the 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, let's say they have 20% of one of the pipelines and 15% of another line’s capacity, that's where our Mcf will flow.

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

It’s Wade. I would assume that if things stay the way they are currently with the strip and in our kind of steady activity profile, that we would probably begin paying some cash taxes later this year in the kind of teen and 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 the 100 million to 150 million a year. And again, that assumes that 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 heading, assuming there's no big changes.

Yeah, and just out of curiosity, what is that like 100 million to 150 million in play on an effective cash tax rate on pre-tax income?

Yeah, it's certainly well south of the statutory rate, the 20% area, it's well under there.

Yeah, are we talking like 10%, 15%? Somewhere in there around 10%?

The effective tax rate is likely around half of the statutory tax rate, but this is a rough estimate. This projection is based on the assumption that we maintain a consistent capital program and that all tax regulations remain unchanged, including IDCs. If these conditions are met, that is what we can expect regarding our effective rates.

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

Thank you all for your interest in SM Energy. Since I’ve got the time, when this started, if you ask me why invest in SM Energy now? Just consider the key attributes. First, we’re producing top tier flow breaking assets in two great basins, #1 and #4 in the country. We’re able to generate significant free cash flow. We’re 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 from NAV or EV from confirmation in the Austin Chalks. So thanks again for your interest.

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