SM Energy Co (SM) 2018 Q1 法說會逐字稿

Welcome to the First Quarter 2018 SM Energy Financial and Operating Results Q&A Call.

(Operator Instructions)

I will now turn the call over to David Copeland, Executive Vice President and General Counsel.

Thank you, Tiffany.

Good morning, and thanks to all joining us by telephone and online for SM Energy Company's First Quarter 2018 Financial and Operating Results Q&A.

Before we start, I'd like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our 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.

For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday, the presentation posted on our website for this call, the Risk Factors section of our Form 10-K that was filed earlier this year and our Form 10-Q filed for this quarter.

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

Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our press release for this call.

Other company officials on the call are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, Executive Vice President, Operations; and Jennifer Samuels, Vice President, Investor Relations.

I'll now turn the call over to Jay.

Well, thank you, David.

I think everybody understands.

It was a pretty straightforward quarter.

So we'll just turn over to you for your questions.

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

In the prepared remarks, Herb, you mentioned you're looking to go to co-development on these zones.

Just want to see when do you think that starts?

How big the pads are going to be?

And is it just going to be the 3 zones of the Lower Spraberry, Wolfcamp A and B or contemplating any other zones as you look at moving to that co-development type of operation going forward?

Yes.

All right, Mike.

This is Herb.

And yes, we've already done co-development of 2 zones and we have for, in this year's plans, co-development of a large pad -- set of pads in the rock ridge -- RockStar area.

So that's going to be late in the year.

And I believe it's 25 wells.

It will be 3 zones and that will be Lower Spraberry, Wolfcamp A and Wolfcamp B. So yes, we've done 2 zones, co-development in numerous places.

Okay.

And so it sounds like you're going to pretty lumpy production between third and fourth quarter.

Is that right?

It will be lumpy.

It just depends on the timing.

In some cases, we have 4 pads that will come on in successive order and they can be a month apart, but that -- it will be a pretty lumpy production.

Okay.

And just wanted to ask, the Lumbergh wells, the Lower Spraberry wells there look really strong.

Did you do anything differently in drilling or completing or flowing those well back?

Or is it just more a function of the geology there?

No.

The Lumbergh wells is -- are standard completion.

There's nothing really special on Lumbergh wells at all.

And of course, they are the 10,000-foot laterals on those.

So it's a great area?

Yes.

It's really a great area.

Good.

And then, I wanted to ask Dave a marketing question.

You guys have gotten out ahead and did a nice job with the basis hedges.

Is that -- do you feel like you're covered there with those?

Or any thoughts on the need for firm transport at this point?

So on the whole market side, we think we're really well-positioned.

Our gathering and sales are diversified to several counterparties and all our counterparties for oil have firm takeaway capacity.

And one real differentiating thing for us is the oil is really high-quality, 37 to 41 API, which is great for Texas refineries.

It doesn't need to be exported.

And then, of course, we're hedging with our routine hedging program where we're really watching that.

And finally, we've got great relationships with all our off-takers.

So we think we've managed through -- we're managing through what we see as a temporary tightness that everybody sees.

Your next question comes from the line of Joe Allman with Baird.

Just to follow-up to Mike's last question.

Could you just give us a fuller picture of the takeaway situation?

So are you seeing any physical tightness now?

And if not, do you expect to see physical -- any physical constraints?

And could you just talk a little bit further about flow assurance?

I have your data on your basis hedges for 2018 and 2019, but talk about, if things did get really tight, your ability to make sure you can actually flow your oil.

Yes.

The answer to the first part of that, Joe, is no.

We are not.

We -- our purchasers and our gathers are well-positioned and so we don't foresee any issues from those counterparties at all.

And we've had a long-standing relationships with them, some of them in other basins also.

So we're -- we do not see any issues with flow assurance.

Got you.

So what do you -- how do you explain the big blowouts we've seen?

Because I've talked to other operators as well and have seen no physical constraints yet, but how do you explain the big blowouts we've seen in the basis?

Yes.

That's -- it's hard to understand, Joe, what all drives the -- how the market is moving, if people see tightness in the future and -- but it would be pure speculation on my part.

Got it.

That's helpful.

And then, on the Eagle Ford shale, so I heard your comments about the fiber optics, which is very interesting.

And I know you're testing new concepts this year.

Do you have any results so far to talk about?

I know you're completing 9 wells in the second quarter as well so I look forward to those results, but any results so far from your own testing of concepts out there?

So on -- let me go to the fiber optic question first.

So that installation was a permanent installation.

And so we've already completed the fraction stimulation of that well.

So we see exactly what happened and we tested a number of different changes in the completion design over typically 6 to 8 stages in each and we're going to -- we're just now starting to flow back on that well.

So we'll see how the completion design changes the influence, the contributions from each stage.

So we're really excited about that.

And we did try several different things in the one wellbore.

And we'll just be sharing that as we get the results in over the next couple of quarters.

Got you.

Anything else to talk about Eagle Ford?

Any other results to speak about?

We only completed 5 wells in the quarter so -- and we didn't have any completions for about a couple -- 3 months before that.

So it's been pretty light in terms of new results on the Eagle Ford.

And of course, we're going to get the 9 on this next quarter.

Your next question comes from the line of Brad Heffern with RBC.

A question on RockStar.

So obviously, the acquisition case for that acreage didn't assume that 3 benches would work, but I was curious if you could talk about the percent of the acreage that you think has been proven out across 3 benches versus 2 benches and so on.

Brad, this is Herb.

Yes, I think in the February presentation, we showed our maps and that's a pretty detailed look at where we confirmed and where we believe the sweet spots are.

And we're continuing our march on expanding that confirmed contour over time.

And you're right, over that northeast edge of our acreage, we've got 3 wells up there, 3 different zones.

So we've been real pleased there and, of course, we're stretching it out wherever we can.

Okay.

And then, a question on the Permian basis hedges.

There's a comment on the slides about how there's 1/3 of 2019 oil production hedge, but the number that I had for your hedges in 2019 is about 17,000 barrels a day and so that would employ -- that would imply a lower oil number than I think most people are thinking.

So is it -- have you layered on more hedges that I don't have in that 17,000 number or any other explanation there?

Brad, when I put numbers in like 1/3 or 1/2, they're really rounded.

So you can assume, for example, 1/2 might be 45% or 55%, 1/3 would be plus or minus a few percentage points.

So I don't think it's -- would work to back calculate off those round numbers.

Okay.

Got it.

And then, finally, do you guys have a location count in the Eagle Ford you could give?

I don't think we've seen one of those for several years.

No.

I think...

No -- this is Herb.

It's in the February presentation.

We gave all this information in February.

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

Just another follow-up on the marketing front for me.

I know you all are very confident in your strategy there, but I was wondering if there was any additional color you are able to provide on what percentage of crude this year is exposed to Midland basis versus Gulf Coast or Cushing and how that might escalate year-over-year into 2019 given your growth profile?

Well, our sales are typically to third parties and it would be Midland basis-priced.

Okay.

And it looks like everything is firing on all cylinders in the Midland Basin.

And I know you all talked about 2019 being directionally lower from a rig count perspective.

I was wondering from a longer-term perspective if you could provide some color on what you all think is the right level of activity that would be necessary to optimally develop your Midland acreage, balancing infrastructure and capital efficiency?

Well, this Jay.

That's a big, big question you just asked.

And in general, what we're going to do at the corporate level is we're focused on returns that will allow us to operate within our own cash flow and generate competitive debt-adjusted per share cash flow growth rates and we're going to optimize based on that.

We will be in a position by the time you get through next year where we've got almost all this acreage held by production in one shape or form.

So we can go at a pace that's going to make sense from an overall corporate returns and growth standpoint.

Okay.

And for my last question, it just seems like the majority of the newer batch of wells at RockStar this quarter were done at 420-foot spacing in the Wolfcamp A versus 500 to 660 feet that you've kind of talked about as being optimally based on the set of results that you have seen.

So is this a case of the wells turned online in Q1 being DUCs that needed to be completed before that observation was made?

And if so, when should we expect wells in the program to kind of adopt the wider 500 to 660-foot spacing?

Yes, Oliver.

This is Herb.

So the 420-foot spacing makes a lot of sense for certain areas and 513 makes sense for areas in 660.

So what we've really been doing is refining what's optimal by different intervals and by different locations.

So it's hard to say there's just one single rule of thumb.

It just so happens where the wells that came on, those 19 wells that came on, the majority of those were Wolfcamp A and they were where we were doing the 420-foot spacing.

So it's really that's what it comes down to.

Yes.

I think when we talked about 500 spacing, we're talking sort of an average number across the acreage.

And we've used that to help people understand our inventory numbers.

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

Can you tell us a little bit more about what you're seeing in the Eagle Ford that lead to the up-spacing and what part of your acreage is that applicable to?

And as a follow-up, would you guys expect better well results heading forward from the up-spaced wells?

Yes, Kevin.

Yes.

So let me just step back a minute.

So we've got this large Eagle Ford acreage position and it's really a great asset and it's not really valued as highly as we think it should be.

And we mentioned over the last couple of quarters in our calls what we're seeing and we're moving to wider spacing and definitely drilling longer laterals.

And then, we're also steering a little bit into different landing zones and then we're working on that frac optimization that I just talked about earlier with the fiber optics.

So we think that with what we're doing in our 2018 program and going forward is that we're going to add significant value to each of the wells we drill, just like when we talked about the Permian when we went to longer laterals that we were quadrupling the value per well.

This is the same sort of thing that we see significant value enhancements by going to the new plan.

And we've got lots of data off-site operators plus when we do a lot of data analytics on our existing wells, we can really see and we're now just putting that program in place.

And we're doing that really where we're drilling, which is basically on the undeveloped leasehold.

And so it's really increasing the value of the undeveloped leasehold that we have.

So is that applicable to the eastern part of your acreage?

Yes.

The undeveloped leasehold in the eastern acreage hold, that Galvan area, that's great rock out there.

Your next question comes from the line of Mike Kelly with Seaport Global.

Jay, you guys done a really remarkable job the last couple of years in terms of your portfolio high-grading efforts.

And just kind of a broad question here.

I just wanted to get a sense of where you stand now, if there's anything kind of left in the garage for you to clear out?

Well, as far as further divestitures go, I think we've proven that we're not shy about making portfolio changes.

If you track our divestitures today, you know that, on average, those assets were sold at very highly values relative to the cash flow they generated, at the same time not materially reducing the amount of our really high-return drilling inventory.

And that's still going to be our objective in any transaction or combination of transactions that we would pursue.

Okay.

And is there -- just to get a sense, is there anything that's maybe front and center on that front, expect to pause there, constantly working it, all the above?

Well, we work on improving our portfolio all the time, but we're not in the market selling anything right now.

Okay.

Fair enough.

And my follow-up is on CapEx.

I just would like to get your sense and your comfort levels with hitting the full year '18 numbers.

I think, on our math, you will have $734 million spent in the first half of the year, which implies a downtick in the second half to get the full year number.

I just want to understand kind of the variables there and your overall comfort there.

Yes, this is Herb.

Pretty much we see, after first quarter, things are right on track with what we assumed, that 10% to 15% increase over last year.

We don't really see any reason to take a different view at this time.

And really, the pace we kind of laid out there, what we're doing in terms of dropping some rigs and frac spreads a little bit later in the year.

So we look on track right now.

And of course, well results we've been really pleased with, too.

Your next question comes from the line of Biju Perincheril with Susquehanna.

Herb, in the Eagle Ford, with the new tech completion test that you're doing, when do you think you will have enough information to get a good idea about the -- especially on the western side of the acreage, the prospect activity there?

Biju, just let me clarify.

So you're talking about in the JV area on the western acreage when we're getting results from there?

Correct.

When you will have -- the JV area, the broader west, north area of your port -- acreage, which is when you would have...

Yes.

Right.

We just got 8 -- the first 8 full D&C wells in the JV.

We just got them online now.

We'll get another 8 by the end of the year.

So you're really talking towards the end of the year that we'll have some months of production from the first 8 and then it will be in the next year that we'll have results from the next set of 8 out there in the JV area.

Got it.

And then, wanted to just to look through the economics of the Eagle Ford versus the Permian.

With kind of $60 oil, it's really difficult for Eagle Ford, it looks like, to compete.

How much of an improvement that you need to see in these wells to where it -- where Eagle Ford can compete for capital in your portfolio?

Well, Biju, first of all, the NGL component is really big on the Eagle Ford, so that's really a key driver.

And so we've shown like in the IR figures in February where NGL spend and that drives it.

And you'll see that they're pretty competitive and what we're doing now is making them even more competitive by expanding the laterals and widening spacing somewhat.

We see those returns really coming out considerably.

I think your question implies something that we don't necessarily agree with.

We think the Eagle Ford can compete with our Permian returns, but clearly we need to drill an amount of spacing that's appropriate for the price environment we're in and the NGL value is significant.

So we really believe that it's a great asset.

It's just not valued the way it should be.

And results from these next-generation wells are going to show us a lot of potential and increase substantially the value of that undeveloped acreage and that's what we're about this year.

Your next question comes from the line of Asit Sen from Bank of America Merrill Lynch.

So on Eagle Ford, I was wondering if you could talk about impact of up-spacing on inventory count and potentially walk us through the impact on NPV of a DSU, if you could.

Okay.

Let me take that, Asit.

It's really the NPV -- clearly, it goes up substantially when you're increasing NPV per well by a considerable amount.

In terms of inventory, we're really talking about economic inventory and that's really a threshold IRR that we use.

So economic inventory, it's really a positive outlook on economic inventory if you look forward, if we get the results that we expect.

Okay.

Okay.

And then, your RockStar position is fairly contiguous.

Can you talk to us about how many locations you will have or you have with an average lateral length of, say, over 10,000 feet?

We put a lot of this data in to our February release.

There's a pretty good rundown on inventory there and you can assume that almost all those laterals are 10,000-foot laterals at this point.

There are no further questions in queue at this time.

I will now turn the call back over to Jay Ottoson.

Well, thank you.

I mentioned earlier, our vision for the company is to be one that generates high returns, can grow with our own cash flow and deliver high debt-adjusted per share cash flow growth rates.

And we're on a path to get there as quickly as we can.

And I'm really happy with our quarter.

We're on track with all the plans, on track or ahead of our trajectory on everything we can come up with today.

So thanks, again, for your time and attention and we'll look forward to sharing our results with you next quarter.

This concludes today's conference call.

You may now disconnect.