SM Energy Co (SM) 2019 Q2 法說會逐字稿

Good morning.

My name is Scott, and I will be your conference operator today.

At this time, I would like to welcome everyone to the SM Energy Q2 2019 Results Q&A Conference Call.

(Operator Instructions)

Thank you.

Jennifer Samuels, VP of Investor Relations, you may begin your conference.

Thank you, Scott.

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 today's earnings release, the first quarter -- second quarter IR presentation and the Risk Factors section of our Form 10-K.

We also filed our Form 10-Q this morning, all of which are posted to our website.

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

Reconciliation of those measures to 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, we have President and CEO, Jay Ottoson; EVP and CFO, Wade Pursell; and COO, Herb Vogel.

I will now turn it back to the operator to take our first question.

Scott?

(Operator Instructions) Your first question comes from the line of Neal Dingmann with SunTrust.

Nice quarter, guys.

My question, Jay, may be for you, Herb.

Just wondering, well spacing is obviously receiving much increased attention largely because of what we've seen now from Concho and some of these other Delaware players.

Looking at your Slide 14, I'm curious to, if you are thinking about space any differently in your RockStar play post the success of the Merlin Maximus?

Neal, this is Herb.

No, we're actually quite pleased with where we are in Merlin Maximus.

You're probably aware, we did quite a bit of work on doing pilot at Sweetie Peck starting in 2016, and that really allowed us to calibrate for each interval, what spacing was optimal to meet on our return objectives.

So no, we're not really seeing any reason to change.

And we're quite happy with where Merlin Maximus is.

And we've got -- I actually have a poster on the wall showing the performance relative to our peer type curve, and it's just doing really well.

I'm looking at 160 days in, and it's doing real well.

But no, I don't see any changes there.

Okay, great.

And then just one last one.

Could you talk a little bit on maybe your pop schedule towards the end of -- the year-end?

I know you have briefly and maybe how this might impact 2020 spending and activity trajectory?

I know you've got just sort of brief guidance out on 2020.

So maybe just in regards of what you can say around that?

And how this schedules will sort of wind down the year might play into what we'll see in 2020?

Right.

Yes, Neal, it's pretty straightforward.

We find that we're much more efficient as an operator, and our contractors work really well with us, if we have a steady level of activity.

And that's why we started saying, hey, let's do our guidance on a CapEx per month basis because that really represents how we like to operate.

So when you look at kind of our cadence completion through the end of the year and early next year, it really -- on how many we get done this year versus our next year, it's really whether a pad comes on this side of December 31 or the other side.

So when you're doing 4- to 6-well pads, if 2 of them come on this side, there's going to -- it's going to look like more completion this year.

The reality is, the CapEx is spent, it's just a matter around that timing either side of the end of the year, but it's steady.

Your next question comes from the line of William Thompson with Barclays.

Jay, can maybe you expand on your comments about ability to shift capital activity to drive positive free cash flow in 2020, if gas and NGL prices remain low?

Is it fair to assume that you're pertaining -- your comments pertaining to maybe moving activity out of the Eagle Ford?

Yes, I think that's exactly what we intended to convey.

And we're -- we do have significant amount of flexibility on our program.

And certainly, we're not going to drill wells that don't make our return expectations, that won't support our goals as the company -- as a company.

I think I'll ask Herb just to make a few comments on -- there may be some a little bit of misunderstanding about how our Eagle Ford obligations are actually determined.

Herb, could you just comment on that?

Yes, I'll just discuss it.

So we operate under consolidation agreements that are negotiated with significant land owners every year or 2. And that really -- those really super seed individual lease obligations, and it's a very efficient way to operate.

It makes a lot more sense for the land owner, it makes a lot of sense for us.

And we work with them to develop a program over the next year or 2, and that -- we do that on a routine basis.

Obviously, low gas and NGL prices aren't good for them either.

But that's really the crux of it.

Okay.

And then as my follow up, it sounds like activity may be more level-loaded in 2020.

May be help us understand how you managed that process given the inherent lumpiness related to larger pad -- larger well pads?

Are you talking about the Permian there, William?

Yes.

I mean I'm talking about like that the overall 2020 program and to have more of a flat run rate of capital spend versus kind of front-end and second half loaded this year?

Right.

The capital program is a flat run rate.

And we, ideally, in the Permian, for example, 6 rigs, 3 frac spreads, steady as you go, that's an efficient way to run.

When -- so the capital profile is pretty flat.

The timing of the production is what can vary because that depends on the pad sizes and where they're located.

Obviously, if you're doing like a Merlin Maximus, that makes it much more lumpy, and when we do have some where we've got 13 to 15 wells in the development.

And maybe if I can sneak one more in, pertaining to my first question.

When could you think you make a decision around shifting capital activity?

Well, we're going to do that...

Is that a function of gas and NGL prices and just maybe thought process around that?

Well, certainly, it's a function of gas and NGL prices.

And with the caveat that there are areas in the Eagle Ford that make significant returns because they are oilier.

When that will be part of our overall budget process as we go through this, this fall, frankly, we won't give final guidance for 2020 until very late this year.

So last year, I don't think we gave guidance till almost the first of the year.

So it's a process we go through.

And I think at this point, given our current operations trajectory, particularly on costs, I think we're in a great spot to achieve our objectives for 2020.

Your next question comes from the line of Kevin MacCurdy with Heikkinen Energy.

Given the glimpse into 2020, could you provide more color on the expected oil mix for next year?

Well, in general, it's going to be up -- it doesn't move as fast as you like because we still have quite a bit of gas PDP in the mix, but it won't be going up.

Our activity is biased towards the Permian, even in our -- in the earlier cases we've shown, and certainly, if gas and oil -- gas and NGL prices stay low, we would be shifting more activity toward the Permian.

Got you.

And in the Eagle Ford, do you have any drilling obligations there next year?

And is there any update on may be an extension of the Eagle Ford JV?

I think we just answered this question.

In terms of drilling obligations, the leases there do have drilling obligations, but we operate under consolidation agreements, which allow us to work with our land owners to determine how many wells are going to be drilled in any given year.

And those are negotiated annually.

The JV -- or annular -- biannually.

And the JV is going on right now, and we don't know whether it will be continued into next year yet officially or not.

And I'll just repeat, whether it is or not, we are not going to drill wells in South Texas, if they don't meet our return hurdles.

That -- we'd be very clear about that.

So we will -- we'd love to have a JV.

We love our JV partners.

We think they're excited about the program, but we're not going to commit ourselves to drill wells, unless they meet our return hurdles.

And this is the same as last year, where we didn't get the JV finalized until late in the year.

And that's kind of what your expectation would be.

You next question comes from the line of Gabe Daoud with Cowen.

Just a quick question on cost.

Jay, you hit on it a couple of questions ago.

But maybe you could just talk a little bit about what was driving the LOE beat this quarter?

And then if you could just talk a little bit about how you think D&C cost per foot can trend this year and, I guess, next year?

Great question.

Yes, that's served.

So our regional teams out in the operating areas are really laser-focused on costs, and they look at every component, and it's really paying off.

And I got to give kudos to everyone who is working this.

So there's been lots of examples of structural changes we can do in LOE.

And for example, we instituted a program to accelerate electrical hookups and reduced number of generators, and that's been a significant reducer to our LOE, that lowers our rental costs.

We initiated a program, which reduces failure rates on some of our artificial lift and this saves a lot in well workover costs.

So you see lower workovers as a result cost there.

And then in higher GORs, we've transitioned from one artificial lift method to under lift and that saves a lot in actual power usage.

So we're really focused on LOE and we've got numerous examples of making progress there, and we're going to continue to do that.

Awesome.

That's really helpful.

And just, I guess, any color on the D&C side?

Yes.

Look, D&C is -- yes.

And Jay mentioned the 10% reduction, and we've already achieved that.

In some cases or for certain types of wells, it's a combination of lower sand costs, which are structural, lower fluid volumes in some of the wells and lower pumping costs.

But then it goes through across a number of other areas, lower chemical costs.

A lot of the ancillary services have dropped in costs.

So that's where we're seeing the 10%, and we're very confident we can achieve that next year in the current operating environment.

Herb, let me interrupt just for a second.

Herb, I kind of feel like, I cheated you out of your opportunity to talk about our well results, but because I did the whole prerecorded call myself.

I know you want to brag about that a little bit.

Would you like to comment just a little bit on our well results for the quarter?

Yes.

So this was a phenomenal quarter again, and we continue to see well results exceeding our expectations or being right on our expectations.

And the Merlin Maximus is the best example where we continue to see it perform at the level we feel we've really found how to optimize our spacing and achieve the returns we want.

So we've always talked about having that 25% return on a minimum on the last well drilled.

And we're finding that we've been able to dial into that really well.

Any other issues on wells this quarter you want to talk about in terms of mix or...

Yes.

So the mix of wells this quarter there, it can be a little bit lower IP and shallower declines just because of where they're located.

And on top of that, we've also shifted on that artificial lift side to lower cost artificial lift, which leads to a little bit of lower IP30, a little bit shallower initial decline.

But in terms of capital efficiency is phenomenal.

And we had a few more lower Spraberry wells this quarter than...

We did.

In our previous quarters as well.

Okay.

Sorry, just want to make sure I give you a chance to address that.

Other questions?

Your next question comes from the line of Mike Scialla with Stifel.

This is actually Guillermo for Mike.

I got one question regarding cost for the rest of the year.

Based on your full year guidance, it seems like operating cost would be a little bit higher for the second half of the year.

Is that right?

Well, so all we're doing, we're not really changing guidance yet.

We're going to just going to work our way through 3Q.

But yes, we're seeing good results on the LOE.

And where we actually come in will depend a little bit on workovers.

So right now, things are looking good, but we weren't ready to change guidance yet.

Okay.

And I have another question regarding the development on the Wolfcamp D and the information.

You've got -- you guys have some very good wells results, perhaps why -- could you provide some comments on future development?

So Guillermo, I am not quite following your question.

You're asking about the Wolfcamp B?

I think it was D.

D or B?

D, D, D, D as delta.

B as in boy?

Oh, D as in delta.

Okay.

Yes.

Wolfcamp D, yes.

So we have a great well result there, and we're monitoring it.

We're looking at where the next location should be.

We have not integrated them into our plants yet.

When we get to the budget cycle in the fourth quarter, we'll decide whether to drill some Wolfcamp D wells, whether to complete some next year or not.

But we're definitely excited about that first result.

And the great thing about the D is, when we built our -- when we did that acquisition and built our evaluation model, we didn't include value for the D at all in that model.

And so this is really very additive to our program.

Your next question comes from the line of Gail Nicholson with Stephens.

I got on a little late, so I apologize if this question has been asked.

But is it right that Austin Chalk, the 2 incremental wells that are being done, are those going to be landed in the same zone area of the Austin Chalk?

Or are you testing anything upper -- in the upper interval of the Austin Chalk?

Yes, Gail, this is Herb.

So the way we've lined up that program is we have accelerated 2 more wells into 2019.

And Austin Chalk one was just a flip over from an Eagle Ford well that we switched to an Austin Chalk and the other was additive to the program.

And those wells are really delineating the Austin Chalk lower interval, the E bench aerially is not testing shallower interval.

We're making plans now on testing the shallower interval, but we don't have that in our plans yet.

Okay, great.

And then is there anything -- and you guys had a very good success, testing different intervals in over at Howard.

Is there anything else that you guys are looking at Howard that you kind of might be on the horizon to test over the next 12 months?

I'll just say, yes, but we're not ready to talk about it yet.

(Operator Instructions) Your next question comes from the line of William Thompson with Barclays.

Thanks for letting me jump back on.

So let Herb talk more about well results.

I'm just looking at Slide 12, understanding a greater mix of Lower Spraberry.

And I know you guys have kind of given us the color that lower start, but shallower decline.

Maybe just talk about how that's performed on the Lower Spraberry side versus expectations?

Okay.

So I think on the Lower Spraberry, it's actually performed better than expected for the one first quarter.

Are you talking about Merlin Maximus or new well results?

Yes, the Merlin -- yes, the influence to the Merlin Maximus, correct.

Okay.

All right.

So William, can you just repeat the question then?

Yes.

Just looking at Slide 12, seen obviously the strong performance here.

And I understand there's a greater mix from the Lower Spraberry, which would have a shallower start, but then a shallower decline.

So I just -- I'm just trying to get a -- how has that performed versus expectations?

Better than we expected.

Better than we expected, and it's not really that big a deviation anyway from -- in terms of better or anything.

And there's a mix on the well.

So no, there's nothing anomalous there whatsoever.

So I guess if you think about that curve, there's a lot of Wolfcamp A wells in that curve.

So if you're doing this well as that curve with more of Lower Spraberry wells, that implies you're doing better than...

And there is small influences, slightly better, but it's not going to be big.

Okay.

And then I know it's kind of early to determine the upsize, the benefit to the upsize spacing program, the longer laterals in the Eagle Ford.

But maybe just kind of comment on what you're seeing there?

And I understand it's very preliminary to see kind of pass on to 20 days of production there.

Yes, let me just say that with what we're seeing, a combination of longer laterals, the wider spacing off of the Austin Chalk in the mix that the returns have significantly improved from 2017 to 2018 and to where we are today and what we anticipate for 2020 with the program we have there.

And every one of those interventions we've made on that program has been beneficial.

And the team has done a great job of sorting that out, really looking at using advanced data analytics, really.

There are no further questions at this time.

I will turn the call back over to the CEO Jay Ottoson for closing remarks.

Well, thank you.

We will be attending several conferences later this quarter and we'll keep you updated on our results and forecast.

Thanks for being on the call today, and have a great weekend.

This concludes today's conference call.

You may now disconnect.