SM Energy Co (SM) 2019 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to SM Energy's 2019 Results and 2020 Operating Plan Q&A call.

I would now like to hand the conference over to your speaker today, Jennifer Samuels, Vice President of Investor Relations.

Thank you.

Please go ahead, Ms. Samuels.

Thank you, Julian.

Good morning, everyone, and thank you for joining us.

Allow me to quickly remind you that we may discuss forward-looking statements about our plans, expectations, and assumptions regarding future performance, these statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

Please refer to the cautionary information about forward-looking statements in the 4Q earnings release, the IR presentation and the Risk Factors section of our Form 10-K, which was filed this morning.

All of those documents are posted to our website.

Our discussion today may include non-GAAP financial measures that we believe are useful in understanding and evaluating our performance.

Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are provided in our earnings release and IR presentation.

Here to answer your questions this morning are President and CEO, Jay Ottoson; EVP and CFO, Wade Pursell; Chief Operating Officer, Herb Vogel.

So we have some very positive news to talk about, so let's get started.

I'll turn it back to you, Julian, to take our first question.

(Operator Instructions) Your first question comes from Brad Heffern from RBC.

I'm looking at the 0-time plot that you guys gave for the 41 new RockStar results.

Obviously, they're outperforming the prior average by a significant margin.

I'm just curious, how much of a driver of that -- was that for the strong 4Q performance?

And then how much of that stronger performance is assumed in the 2020 guide?

Brad, this is Herb.

Yes.

So the 41 wells that we showed there, they're excellent performers.

There are no unbounded wells in there at all.

They're all fully bounded and half bounded.

And so yes, they're part of the reason 4Q performed really well.

And then some of that performance will continue into the first quarter and normal decline, normal decline curves, nothing really outstanding there.

The one thing I will say is that we do periodically have shut-ins to keep from flaring, in some cases, and we did that during fourth quarter and again in January.

And then we do have events like we had a 12-inch snowstorm in Big Spring, believe it or not, at the beginning of February and that limited our access to some wells.

So we have wells that perform as predicted.

And then we have other events that we got to consider with third-party gas processing, et cetera.

Okay, got it.

And then I was wondering if you could just comment on inventory.

At this point, do you have any sort of numbers that you could put around how much of -- how much Midland Basin inventory is left either in terms of wells or years or maybe in terms of the percent that's been developed at this point?

Yes.

Brad, this is Herb again.

So the -- what we did in -- I think it was Slide 17, we showed frame of reference, since there are so many different basis between companies on how they count inventory, some do just the sticks on a map.

I think I had -- put that in the call, the taping yesterday.

Some do sticks on a map, some have IR cutoff and then the cutoff vary.

So the way we look at it is, we just have more than a decade of some of the highest quality inventory in the entire Midland Basin.

And that's why we show that is because of the inventory we have is really high quality.

And then we're continuing to grow inventory as we look at additional intervals.

And you know we really scratched the surface on that over the last year, and most of our developments to date have been those co-developments of Lower Spraberry, a little bit of Dean in there, Wolfcamp A and Wolfcamp B, and we vary that co-development depending on the specific geology of a drilling spacing unit.

I hope that answers it.

Your next question comes from Neal Dingmann from SunTrust.

Two questions, Jay.

My first question for you, Herb, on South Texas.

Specifically, looking at Slide 20, you certainly had strong results on that latest Briscoe well.

So does this give you confidence that further wells maybe in that northern area could be as high liquids or is positive?

Just any color you could talk on that.

Yes, Neal, yes, we're really pleased with that well.

We are -- immediately started drilling another well in the general vicinity, the Austin Chalk, to confirm that type of result.

Whenever you have just one well of that nature, you want to check it out.

But overall, the overall average, what we're really pleased to see is that that's pretty much -- if you average those 5 wells, that's about in line with a Delaware Basin average that we've seen from a couple of different banks issuing and that particular well is considerably better than Delaware Basin wells.

And we don't have any takeaway issues here.

So we're pleased with it, and we're going to go confirm it, and we're going to drill longer lateral into it in that area.

Okay.

Then my second question also on South Texas.

You mentioned in prepared remarks that a potential JV in the play.

I'm just wondering, could you speak to when, Jay, when you guys are weighing all the options on this, how you think about keeping versus a sale versus JV or some other structure?

How sort of all that thought process is going?

Yes, thanks for asking the question.

I think we're doing exactly what all our stakeholders should want us to do, which is exploring every option to generate more economic activity and value from the South Texas leasehold that we have.

We've engaged Scotiabank to help us, do a broad search, including, really, for funding partners, including international players and large gas consumers.

It could be that we'll receive some proposals as part of that process that could involve an earn-in to our acreage or a purchase of some or all the assets.

Our existing PDP covers all our volume commitments or MVCs, some people call that.

So -- and our plan assumes that nothing gets done.

I want to be real clear about that.

So anything that we do here is really upside to our plan, which is to drill economic wells.

So with that said, again, this is a -- it's obviously a difficult A&D market out there.

We're doing what we think any active as good activist management team would do to pursue all the alternatives and no specific time line.

We're going to -- anything we get here will be upside to what is a very robust plan.

Did we lose?

What happened?

What happened?

Long answer.

Feel to call.

Your next question comes from Gabe Daoud from Cowen and Company.

Jay, I guess, just given a decrease in Permian footage turn to sales or expected to turn to sales in '20 versus '19, I think there's some worry over the trajectory of Permian volumes throughout the year.

And even though it's early, also some worry about how Permian volumes trend into 2021.

So can you maybe just address the cadence for this year and how you view the Permian program overall evolving over the next couple of years?

Yes, Gabe, this is Herb.

Yes, I don't really see any concerns on cadence at all.

Really, what we're doing is we're growing oil production at a pretty good clip there at 5% to 10%.

And we're really working on the free cash flow, and that's really the focus, and we plan for free cash flow to continue to grow, 2020, 2021 and beyond.

So it's a program that I think does all the objectives we set from a strategic level.

Got it.

And then I guess just as a follow-up.

You're exiting 2020 in the Permian with quite a bit of DUCs.

I guess, is that a natural backlog?

Or do you anticipate maybe exiting 2020 with something less than entering the year?

I think it's about 40 DUCs or so.

Yes.

Gabe, the DUC count, it's just a normal course of business with our -- we're running 5 rigs, and we're running 2 frac spreads.

Those rigs are running continuously.

They're drilling at pretty much the similar lateral length wells.

And then the frac spreads, it's just the size of the pads.

Sometimes you're going to have 6 well pads, sometimes you're going to have 2 well pads, some 4. So it's just -- and you bring all those wells on at one time.

So that can just move your DUC count around.

I think the DUC drain down in 2019 was probably 5 wells.

But that's just a matter of when the pads are timed.

That's all.

There's no specific strategic objective to do any drawdown or build of DUCs.

(Operator Instructions) Your next question comes from Mike Scialla from Stifel.

Want to see if you could give a few more details on your plans for South Texas of the 16 wells planned to drill, and I guess, 9 completions.

Do you know at this point how many of those are planned to be in the Austin Chalk?

Mike, all 9 completions are planned to be in the Austin Chalk at this point.

Okay, interesting.

And hypothetical, I guess, if you did do something in the Eagle Ford, say, even flat out sold it, would that change your plans for the Midland this year and how so, if at all?

Mike, this is really speculative now because the odds are that nothing happens.

Our focus is on -- would first be on reducing leverage, generating free cash flow and reducing leverage.

That's our -- those are our priorities.

Got it.

And a question for Wade on the 2022 notes.

Just your thoughts on ability to do anything with those or is the market not amenable to that right now?

Yes, good question.

Yes, they're still a ways away.

They are '22, so they're -- it's the end of the year, they're nearly 3 years away.

We'll just continue to generate some free cash and hopefully chip away at it, Mike, and look for better opportunities than I think exist right now for any potential refi, but we like where we are, though.

Your next question comes from Gail Nicholson from Stephens.

I apologize.

I've got on a smidge late.

So I'm not sure if this is already answered.

But you guys continue to show really good efficiency improvements, both on the drilling side as well as the completion side.

I was just curious where current nonproductive time is today?

And do you see if that's some incremental improvement that you could continue there and pick up even more efficiency gains in the '24 time frame.

Gail, this is Herb.

We do detail nonproductive time evaluations of every well we drill and every well we complete and there's no single silver bullet.

It's a lot of grinding work to do that and you work closely with the contractors.

The biggest gains tend to be in improved communications between the different aspects.

If you've got 13 contractors out there on a completion going on, having the best communication is what really drives it.

So that's really the answer, no silver bullet, lots of grinding work.

Okay, great.

And then this one is probably maybe for Wade.

Hedging, you guys have a really strong hedge book this year.

How are you guys thinking about '21?

And with the continued volatility that we have experienced in the commodity, has the hedging strategy changed at all?

We had -- that's a great question.

And we do have a really -- we like our hedge book for this year.

I think we have 80% of our oil hedged.

And we will strategically just do something very similar as what we've done in the last year or 2, and that's watch the strip and pick a price that we feel confident in.

And we've already put a few hedges in the first quarter of '21, and we'll just continue to try to opportunistically layer on hedges, but we will continue to add hedges as we move through '20 looking into '21.

Now short answer is we haven't really changed anything strategically.

We just -- we'll watch it closely and as we can, we'll lay our hedges in.

We have no further questions.

I would now like to turn the call over to Mr. Jay Ottoson, President and CEO, for closing remarks.

Well, I'd just like to say thanks to everyone who joined for your time and attention today, and we look forward to talking with you at the end of the first quarter.

Thanks.

Ladies and gentlemen, this concludes today's conference call.

Thank you for your participation.

You may now disconnect.