SM Energy Co (SM) 2024 Q1 法說會逐字稿

Greetings and welcome to the SM Energy's first-quarter 2024 financial and operating results Q&A.

(Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Jennifer Samuels, Vice President, Investor Relations and ESG Stewardship.

Thank you.

You may begin.

Thank you, Maria.

Good morning, everyone.

In today's call, we may reference the earnings release, IR presentation, or prepared remarks, all of which are posted to our website.

Thank you for joining us to answer your questions today.

We have our President and CEO, Herb Vogel; and CFO, Wade Pursell.

Before we get started, I need to remind you that 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 5 of the accompanying earnings release, and the Risk Factors section of our most recently filed 10-K, 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.

Got that out of the way.

Also, look forward look for our first-quarter 10-Q filed this morning.

And with that, I will turn it over to Herb for just a brief opening comment.

Herb?

Thanks, Jennifer, and good morning.

Thanks for joining us.

We're obviously very excited about 2024 is shaping up for SM Energy.

So let's go ahead and get started.

I'll turn the call back to Maria to start taking your questions.

Maria?

Thank you.

We will now be conducting a question-and-answer session.

(Operator Instructions)

Zach Parham, JP Morgan.

Thanks for taking my questions.

Just wanted to ask on the buyback first.

You've talked about, in the prepared remarks, ratable pace through the buyback for the remainder of the year.

That would imply around $60 million in buybacks per quarter.

With the current commodity prices, it seems like you will have a significant amount of free cash flow that will allow you to build a lot of cash even after paying the base dividend finishing off that buyback authorization.

How do you think about using that excess cash?

Could further accelerating that buyback make sense?

Just trying to get a sense of what happens with that cash.

Yeah, good question, Zack.

This is Wade.

Good morning.

The guidance on assuming ratable buybacks, I think it's just the best way to model it right now.

Obviously, things never happen that rateably, right?

And as we go through the quarters, we opportunistically repurchase during the open windows.

And you could see -- under your scenario with higher commodity prices, that's generating more free cash flow, you could see us buying back at a little bit more accelerated pace than that, given what the opportunity set is before us.

So that could happen.

And many people have asked what are you going to do when you get through the commitment, and the Board will consider that.

And I can imagine it being possible that we would continue on with a new buyback, but certainly no guarantees of that at this point.

Thanks, Wade.

Just to follow up, in the prepared remarks, you mentioned flattish production in 3Q and then kind of another step up in 4Q.

That seems to indicate you would exit the year with oil in the upper 70s.

Is that a fair number?

Just trying to get a little bit more color on what that trajectory of volumes would look like through the back half of the year.

Yeah.

I think that's reasonable, mid-70s-ish given what we said.

What we said about the third quarter being flattish, it will be up.

I think what's changed a little bit is the second quarter is, obviously, with acceleration higher than it was before in our guidance.

So I think you're reading that pretty well, but you can assume the third quarter is up somewhat over the second quarter.

Gabe Daoud, TD Cowen.

Thanks.

Hey, good morning, guys.

Thanks for the time.

Maybe I was hoping if we could start at Klondike.

You mentioned you did some science there during the quarter and maybe starting to complete those eight to nine wells, where I think results should be ready by the third-quarter call.

But just curious if you could maybe talk a little bit about some of the science work there, some of the Deans in the area look quite prolific on oil-productivity-per-foot basis.

So just trying to get a sense if we could assume or expect similar results out of your program.

Yeah, Gabe, this is Herb.

We're quite excited about Klondike acreage, and we've already drilled a four-well pad and completing it right now.

I will say on the science side, we did take a vertical pilot hole down quite deep and did a lot of sidewall cores and the high-end logs through that interval, so we could assess all the intervals that are potentially perspective out there.

But we're focused now on the development of those -- initially, the Dean and those eight to nine wells this year, and the first four will be online during the second quarter.

So it looks like a great play for us.

And you know, we have quite a few wells offsetting into the Southeast plus the wells that came with the acquisition in Reliance -- from Reliance.

That's right.

Actually, that's helpful.

I guess as a quick follow-up to that, just sticking to Klondike, 20,000 net acres, if you were to progress towards a true development program, is there any type of infrastructure spend that we should be thinking about up there?

There is quite a bit of infrastructure there, but mainly it's getting the gathering lines in place, so we don't have to truck as much and getting the gas lines built to the scale, which is a lot of the midstream.

But otherwise, it's just pretty much normal equipment up there.

Okay, great.

And just the last one, the South Texas drill-to-earn, any additional color you can provide on that?

Thanks, guys.

A lot of people are wondering, how does the drill-to-earn work?

So they're not familiar with it.

And generally, drill-to-earn is where you have agreed to drill a well or wells in return for acreage.

In this case, we're going to operate and drill wells to gain a 50% working interest in around 16,000-acre block.

So that will get us about 8,000 net acres.

The other details around that drill-to-earn really are kept confidential between us and the company that farmed out to us.

Tim Rezvan, KeyBanc Capital Markets.

Good morning, folks.

Thanks for taking the question.

I want to follow up on Gabe's question on Klondike.

We did analysis of the area, and you all have talked about the Middle Sprayberry and the Dean.

The Wolfcamp A looks extremely strong, which sort of offset results.

So just curious, among these three initial wells being completed, excluding the science well, can you talk about what intervals you're targeting and kind of maybe why you have been talking about the Wolfcamp A as a primary target on that acreage?

Sure, Tim.

But one thing I want to correct you on that there.

There will be four producers; just one of them, we took a pilot hole down first.

Then we plugged back and drilled the lateral.

So there are four wells there.

Just one of them, we have that vertical that we just gathered data on.

So it's great to hear that there's prospectivity in the Wolfcamp A. I would say we are not counting that if we're surprised, and the thermal maturity is higher for some reason there than we expected to be.

That'd be great news.

But we're really counting on us being more a migrated oil play, which I've talked about before, which is oil comes from a bit deeper in the basin and migrates into the sandstone intervals.

And that's why they are so prolific up there.

Okay.

And then are these initial four wells all Dean or

--?

Yes, they are.

They're all Dean wells.

Okay.

That's great.

Appreciate that.

And then a follow-up.

I think the comments on the Briscoe pad and the stacked pay opportunities are a pretty interesting.

Some other public companies are talking about that.

I know it's early days for from one pad, but a big marketplace debate was on the validity of your claims that you had 300 locations there.

And I guess just to help kind of frame the resource, if this stacked pay proves to be something you can replicate, does that 300 location count kind of move up dramatically?

I'm just trying to understand sort of what the significance of this test that you do and that you disclosed.

Thank you.

Yeah, Tim.

I would say it's not that much of a big increment in a test.

The only difference is really that lower wells are fully bounded versus in our other places, they've been half bounded.

But we've had fully bounded in the upper interval several other pads.

The thing to note is these are space is about 625 feet, and we've done that before.

These go between two subtle differences in a landing zone in the upper Austin Chalk -- the middle Austin Chalk and the upper interval that we've developed.

So it's just really exciting because of how productive they are, how oily they are, and how NGL rich they are.

And those wells on that one pad are between 11,600 and 14,500 feet long.

So we didn't have difficulty executing there.

And the other three are between 11,900 and 14,000 feet.

So they're long laterals too, and that just really helps the economics also, and they are oil-rich.

So really excited about it on that area, and you can see the strength of the wells and just how they started.

But it's not like they're a really big step in any way other than the bounding of the lower Austin Chalk wells.

(Operator Instructions)

Oliver Huang, Tudor, Pickering, Holt & Co.

Good morning all and thanks for taking my questions.

Just wanted to start on -- the efficiency is certainly good to see that continue to capture there.

Was just kind of wondering what you all kind of achieved in Q1?

Is it something that's already been baked in for new plant activity starting in Q2 when you're kind of providing the quarter ahead of full-year outlooks?

Or is there kind of a wait-and-see aspect to it since it's kind of only a quarter before kind of begin that fully on that incrementally a faster pace that we saw?

Yeah, Oliver, we know when we change guidance, that means we've got a lot of confidence that it's appropriate to include it.

So we're continually working new aspects of efficiencies in, and we have quite a laundry list that our team's running through right now that looks quite attractive, but we're not counting ones unless we see them working.

So the big ticket items for us right now are the increased substitution of natural gas for diesel and pumping operations with those DGBs -- fleets that we're employing.

And Wade mentioned those on the prepared remarks, and that has the added benefit of reduced CO2 emissions from completion operations.

Then we're seeing quite a bit in the way of efficiency gains in drilling.

So this translates to a number of feet we drill per day.

There really, it's more advanced and reliable downhole equipment.

So you don't have to trip the bit as much.

And we're using rotary steerable assembly, so we can keep the bit on bottom longer.

That helps also.

Then on the efficiency -- on cost efficiency side, a big one is using existing central production facilities that now are sitting there with some latent capacity and that avoids the need for capital into new facilities.

We knew all along about what's going to happen, and we're just starting to see it really happen in a pretty significant way now.

And then we're also bundling some services between South Texas and Permian.

So we've got the benefits of the scale of the full operation between the two areas, and that helps.

And then you know how activity has reduced.

So rig counts are down; frac-spread counts are down.

So we're actively rebidding services and seeing discounts that way.

And I can't tell you when that will stop or how much more we'll get there, but that obviously is the contributor.

So that's a list of things that I'd say we're highly confident in and not a list of things that we're still pursuing.

Okay.

That's super helpful.

And maybe for a follow-up and then you mentioned earlier, some of the details are confidential on that drill-to-earn, but I just wanted to try and clarify, are you all responsible for 100% of the DMC for that 50% working interest that you kind of referenced?

And is there any sort of details in terms of how many wells you're planning to do on that acreage this year?

And if that's already embedded within the full-year well count out of the South Texas region?

Yeah.

Okay.

You got two questions there.

The first, we can't reveal or divulge details on the deal.

But I'd say no is the simple answer to your first question there.

No, we're not saying everything for the 50%.

And then the second question was, have we baked this in?

Yeah, we knew the deal was far enough along when we set the budget in February that we integrated that into our plans for the year -- the three wells that we'll drill there this year.

There are no further questions at this time.

I would now like to turn the floor back over to Herb Vogel for closing comments.

Hi.

Thanks, Maria, and thank you for joining us, and we look forward to seeing a number of you at upcoming events.

This concludes today's teleconference.

You may disconnect your lines at this time.

Thank you for your participation.