SM Energy Co (SM) 2018 Q2 法說會逐字稿

Good morning.

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

At this time, I would like to welcome everyone to the SM Energy Second Quarter 2018 Earnings Q&A Conference Call.

(Operator Instructions) I would now like to turn the call over to Jennifer Samuels, Vice President, Investor Relations.

Please go ahead.

Thank you, Kelly.

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

I hope you've all had the chance to take a look at our second quarter earnings release and to listen to the prerecorded webcast with the accompanying slide presentation.

Second quarter results were outstanding, and we look forward to taking your questions.

First, I need to remind you that during today's Q&A discussion, we will be making 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 included in yesterday's earnings release and IR presentation, the second quarter 10-K, which was filed this morning or Form -- or 10-Q, excuse me -- or Form 10-K for a discussion of these risks.

All are available on our website.

We may also discuss non-GAAP financial measures that we believe are useful in evaluating our performance.

Reconciliation of those measures to the directly most comparable GAAP measure can be found in the earnings release or IR presentation.

Here to answer your questions are CEO, Jay Ottoson; CFO, Wade Pursell; and EVP Operations, Herb Vogel.

So let's get started.

Kelly, please open up the call for Q&A.

(Operator Instructions) Your first question comes from the line of Mike Scialla from Stifel.

Congrats on the quarter.

Wanted to ask Howard County, looks like some competitors have drilled some pretty good Middle Spraberry wells there.

Any plans to test that zone?

And maybe plans on the Wolfcamp D as well?

Yes.

Mike, this is Herb.

Yes, we plan to complete a Middle Spraberry well late in the year.

And we'll be testing in the Wolfcamp D and that would be next year, so that's where we stand.

But yes, we have noticed those great Middle Spraberry wells and nearby Wolfcamp D wells also.

Okay.

And turn over to South Texas.

Just wondering any thoughts on testing the Austin Chalk there, and if so, would that be part of your joint venture?

Okay.

So first, yes.

We have drilled a well into the Austin Chalk.

So we're flowing that back currently.

We've seen great yield from that well, but it's early days.

We just started flowing back just a couple weeks ago, and that is not in the JV area.

Your next question comes from the line of Paul Grigel from Macquarie.

Maybe one for Jay or Herb here.

As we look at CapEx coming down a little bit in fourth quarter and the large pad looking to start up sometime during the first quarter, realizing that can move around, what's the thoughts around the potential for fairly lumpy growth as you move out of the back half of -- excuse me, back half of '18 and into the start of '19?

Yes.

So I guess, if you look at it, we're on a growth trajectory, and Permian's definitely got some great momentum going, and we should see Permian grow into 1Q '19.

But by how much it grows will really depend on that big Merlin Maximus set of pad, the 25 wells.

So as we get closer to the end of the year, we'll pin down where we're actually going to be 1Q versus 4Q.

So that's really where it stands.

But you got it right that it's going to be lumpy from those 25 wells coming online or anytime we do the co-development on big pads.

Okay.

And then, I guess, just following up on the Merlin Maximus pad.

How do you guys look at infrastructure and takeaway, I guess, on 2 parts, one on the gathering and processing and just general oil transportation on the pad and around the pad and then on the long haul as well from kind of such large flush production?

Okay.

So there's a lot there in your question.

But the key is that we really plan ahead for this, and we have very good ability to forecast what the volumes are going to be out of the wells, and there's some timing issues.

But we're building the capacity, and then we have the ability to tie in pads nearby so that it's efficient capitalized on the facility sizing.

In terms of the takeaway, I think you probably heard in the remarks from yesterday that we've got all our forecasted volumes pretty much lined out on where they go and who's taking them, and they're all firm contracts.

So that's all already integrated into all our plans.

Your next question comes from the line of Oliver Huang from Tudor, Pickering, Holt.

In the release, you've pointed out that 7 of your wells were bounded on the Kramer-Costanza development.

Just wondering if you might be able to provide some detail in terms of what you all have observed for the bounded wells versus unbounded wells in the early going?

Okay, yes, Oliver, this is Herb.

So it's, obviously, early days with the Kramer-Costanza pads.

There's 14 wells altogether, and 9 of them have reached their 30-day IP.

So we'll be laying that out.

But so far, I can say the IPs looks great and pretty much in line with elsewhere, and some of those are 420-foot half-bounded wells.

Some are 660-foot half-bounded or fully bounded wells.

So it's a great test, and so far we're real pleased with the result.

Okay, perfect.

And for my second question.

I was just wondering on the Merlin Maximus 25 well pad that is expected to be flowing in Q1 of '19, wondering if you all might be able to provide detail as to how many wells in each zone this cube consists of and the spacing design that you all will be employing within each formation?

Yes.

We haven't provided that in the past.

But I can pretty much line it out for you.

So there -- just off the top of my head, I remember about 9 Lower Spraberry wells, about 11 Wolfcamp A wells and about 5 Wolfcamp B wells.

And we're going to vary the spacing kind of between -- there's really 4 pads there, and there's the Merlin pads and the Maximus pads.

And on one of those we have the Lower Spraberry wells at 770-foot spacing and the other about 580-foot spacing.

The Wolfcamp A well, some will be on 660 and some will be on 420.

And Wolfcamp B, some will be on 1,320 and some will be on 840, and those are spacings within zone.

So it's a fairly extensive development and pretty much an upscaling from what we did at Kramer-Costanza.

(Operator Instructions) Your next question comes from the line of Michael McAllister from MUFG Securities.

You went and presented -- or Herb talked about Eagle Ford value creation.

And I was hoping that I could get more color on that, specifically the comment that says in this current commodity price environment.

Because that implies to me that as long as oil is above $60 this is an area that maybe not can compete one-to-one with what's going on in the Permian but does have an attractive quality to it that fits the SM model.

Is that the way to look at it?

Well, that's kind of an interesting question.

I guess our view of this is that we're talking really about the gas price environment in the Eagle Ford because it's largely gassy asset.

It's a great asset, but obviously, we started developing that asset when gas prices were much higher.

So we're adjusting our spacing, adjusting our program to the fact the gas -- we think gas is going to be $3 or a little less for a significant period of time.

So what we're doing is -- with through the outspacing of longer laterals, better completions that we're doing is we're really pushing the -- that project to make the kind of returns that we make in the Permian so that we can be truly competitive there.

And as we've said a bunch of times, we think our best course of action for now in the Eagle Ford is just to further demonstrate what we believe is the large value of our undeveloped acreage there.

Okay.

So it's not like you're targeting things that are more liquids?

It's just that you're trying to make it more attractive or -- you're trying to figure out what you have that can work in a $3 price environment, is that the way to look at it?

Well, yes.

I think -- we know that a lot of this -- this acreage will work in a $3 price environment if you drill it at the right spacing.

Over time what we had done, when gas prices were higher, we had drilled this down to a much tighter spacing.

This is Javan, by the way.

And what you've seen, and Herb talked about this in the -- during the recorded comments, is we have progressively now started moving back to a wider spacing and drilling much longer laterals.

And we know based on our history in the asset and the work we've done that those longer lateral, wider-spaced wells can make much higher returns in this gas price environment.

Your comment on higher liquid content, we are looking at landing zones that have higher liquid contents.

In fact, Herb mentioned the Austin Chalk just a minute ago.

Clearly, we anticipate those having higher liquid contents as well, which simply improves the economics as we look at that.

NGL prices, of course, have been very strong, and all this is wet gas generally.

And so NGL prices have actually been significantly helping our economics.

So the overall position here is we have a very sizable position there with a lot of inventory in it.

We think we can demonstrate to people that, that inventory can compete at a tier 1 kind of economic level.

And that's our current program in the Eagle Ford.

Okay.

So at some point in 2019 with the activity that you kind of are ramping up a little bit, we could expect a quantification of that -- certain amount of locations that have a certain amount of economic viability?

Sure.

Yes.

And I -- generally, we give an inventory update once a year after we finish reserves.

I think we've indicated that we won't really have the true fully up-spaced wells data until sometime next year.

So it will be next year sometime before you'll see all that.

But I will tell you we have a lot of confidence because we have a lot of wells -- older wells that we drilled in the Eagle Ford that we can look at performance on wider spacing, and those wells do perform substantially better than the down-spaced wells that we've drilled.

Yes, I think I mentioned in the remarks that we were seeing double the production.

On the wider-space well.

Wider-space well.

Just based on our historical data.

Yes.

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

I just want to see if I can get an update from you on well costs in the Permian now that you're drilling a lot faster, completing more quickly than you anticipated, and the locally sourced sand is helping out.

Want to see how that's being balanced against service cost inflation.

Yes, Mike.

This is Herb.

Yes, we're definitely seeing our well costs from very recent from earlier in the year we're seeing them drop.

Obviously, the sand -- local sand is helping significantly.

Pumping services costs have softened a little bit.

That's offset a little bit by rig rates being up a little bit.

And then we anticipate some of those tariffs on steel will have somewhat of a impact, but it's relatively small because it's such a small proportion of our well costs.

But all in, yes, it's -- it looks like -- when I'm seeing AFEs today versus 2 quarters ago, they're lower.

And we'll see how it plays out as we get to the end of the year.

But all our inflation expectations for the year were pretty much right in the range of what we thought it would be.

And pretty much the entire market's turned out like we thought it would.

That cover it?

Yes.

Can you put any numbers or ranges around the 10,000-foot lateral?

Well, I think we'll do that at the beginning of the year.

We'll just come out with the numbers because, obviously, with the number of changes that we make and how many wells are on a pad, a number of different things will influence that by a couple hundred thousand dollars here or there.

So I didn't want to be pinned down to a straight number.

Okay.

Fair enough.

I guess -- I know it's too early to put any hard numbers around 2019.

But just in relative terms, you're dropping a rig earlier than you had anticipated.

As you look into next year, I know the balance sheet has been a real focus for you.

Can you say even in general terms relative to 2018 what you think CapEx in the Permian would look like?

You're looking at flattish or up, down?

Mike, we haven't really changed anything from the February plan that we put out.

I mean our expectations for '19 look the same.

And I think overall, our CapEx was expected to be down about 15% between 2018 and '19.

And that's still our expectation.

And we expect to basically generate the cash flows and production that we put forward.

At this point, we don't really have any change to talk about.

Yes.

That 15% decline in production was associated with that...

Capital.

Capital, sorry, similar number of completions.

Okay, good.

Anything you can say about the 9 Eagle Ford wells that were completed during the second quarter?

Yes.

This is Herb.

So the completions that we've got online now, and there were several that came on in May.

I think 8 in May and another 4 in June.

They're all in the Eagle Ford East area.

Some of them are kind of in the center part of it.

The last 4 are way on the west edge -- Southwest edge of it, and they're all doing great.

The ones -- the 4 to the Southwest are, obviously, a little bit lower yield, but they're performing great in terms of where they are.

Early days, but we're real encouraged by the results.

Can you mention spacing on those?

Yes.

Those are at within zones, 625 feet.

They're both upper and lower.

And so between upper and lower, if you're looking down on them on planned view, they'd be at 313-foot spacing.

So they're the wells that were drilled after the pilots on that spacing.

So they're not as tight as some of the pilots were.

They're not as widely spaced as the wells we're drilling at this point.

Right, right.

The ones that we're looking at in the future that go wider where we will widen the upper Eagle Ford in particular and then have the lowers are around 625-foot spacing.

Got it.

Any impact on the parent wells when you completed those?

Well, so where those are, there's not that much parent well -- there's no parent wells immediately in the vicinity.

That's at least 625 feet away.

So no.

Your next question comes from the line of Paul Grigel from Macquarie.

One quick follow-up.

Just on the CapEx increase, you mentioned increased working interest.

Could you walk through if you're seeing that from -- is that acreage trades, non-consents, ability to kind of incremental bolt-ons?

Just kind of curious what's the key drivers behind that.

Yes.

Sure, Paul.

The $30 million that we spent on increased working interest or plan to total for the year so far is really from -- acreage trades is probably the predominant piece, where we've traded out of acreage and then wound up with a higher working interest in wells we were drilling.

Some of those have been completed.

Some are still DUCs.

Then there's another range of where we have non-consents from other parties, and we don't know what their circumstance are, whether they don't have the finances or whatever.

And those depend on whether there's a joint operating agreement or not, but there's a back-in after payout for them, and that varies -- the penalty varies between 100% and 300%.

So that's really how it kind of stacks up.

And the interest can be just a fraction of -- a tenths of a percent interest to double digits in some cases.

And have you seen any pattern within the non-consents, be it public E&Ps, private E&Ps, kind of -- you can call small mom and pops?

Anything along those lines on a pattern?

No.

It's more like aerially certain big parties will be on one side, and they'll just go ahead and non-consent and take the back-in after payout, if they choose to do that.

And then where the acreage trades are it's really been up to us on getting out of some scattered acreage that going to be of low value to us and building up our working interest in places we're actually drilling and can get value.

Your next question comes from the line of Owen Douglas from Baird.

Wanted to sneak a quick one if I could.

So just in terms of understanding the cadence for the second half of the year.

What's your expectations with regards to the number of DUCs you're going to end the year with?

This is Herb.

I think 519 is it?

That shows kind of our projection of DUCs.

It's got to be around 80 at the end of the year between Eagle Ford and Permian.

Great.

That's -- I'm sorry, I missed what you just said.

Sorry, it's Slide 19 in the backups.

In the appendix.

In the appendix of our presentation.

Okay, great.

So in the backup there.

So just in terms of kind of understanding.

So you're going to be sort of ending with that DUC level -- or that's your expectation for where it's going to be.

As far as sort of, I mean, what does that sort of tell us as far as the beginning of '19 and sort of whether we should expect there to be another kind of front-end burst of activity?

Well, we already -- we discussed earlier that this 25-well Maximus -- Merlin Maximus pad, which is in that DUC count as we go toward the end of the year.

So there's a big chunk of DUCs that'll get completed in the first quarter.

But there will be -- then we'll be building DUCs as we go along.

So I mean, I think in general you should anticipate that, that DUC count will be relatively what we'll be at most of next year.

Okay.

That is helpful.

So as far as with the DUCs being kind of fairly similar, should I be thinking then 2019, '18 budget roughly flat?

Or how should I be sort of thinking about your capital expenditure budget?

Well, as we discussed just earlier in this call, we expect our CapEx in 2019 to be about 15% lower than '18.

A lot of that is just cost savings on sand and other things that we built into our forecast.

In general, we'll complete about same number of wells.

Your next question comes from the line of Oliver Huang from Tudor, Pickering, Holt.

Just had one more follow-up question.

Good to see that the use of local sand is really starting to flow through on the cost-savings front.

But was just wondering towards what levels are you all planning to ramp usage to?

When this might be carried out by?

And how much of the local sand savings have been baked into the latest guidance for 2018 and how much is baked into your 2019 plans?

Okay.

Oliver.

This is Herb.

You laid out quite a few follow-up questions there.

So we're increasing the proportion of local sand progressively as we go through the year.

Right now, I think we're at about 36% in July -- June or July, and we're targeting getting to 80% by the end of the year.

And you can just anticipate significant savings from there.

We baked in, in our budget a certain ramp on the local sand volumes, and that's integrated into what we have.

Whether we exceed that or not depends a little bit -- we also had a forecast on what the pricing would be on the nonlocal sand.

Obviously, our local sand is contractual, so we know what that will be.

And that -- where that comes in compared to expectations will drive, ultimately, where it comes in.

But right now, everything is looking good on the sand side to achieve all we expected.

And I think we publicly mentioned before that we're expecting cost savings on the order of $400,000 a well for local sand use, so that's a pretty decent number to use.

And there are no further questions at this time.

I will now turn the call back over to Jennifer Samuels for closing remarks.

I know it's a busy day.

So thank you all for taking the time to join us, and I look forward to any follow-up call.

This concludes today's conference call.

You may now disconnect.