SM Energy Co (SM) 2017 Q3 法說會逐字稿

Good day, and welcome to the SM Energy Third Quarter 2017 Earnings Q&A Conference Call. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Jennifer Samuels, Senior Director of Investor Relations. Please go ahead.

Thank you, Nicole. Good morning, everyone, and thank you for joining us for today's Q&A call. I hope you all have had the opportunity to review our third quarter earnings release, slide deck and accompanying prerecorded discussion that was posted yesterday afternoon.

We are certainly very pleased with our third quarter performance, notwithstanding the challenges to our South Texas team presented by 2 serious storms, and are pleased with how this performance sets up the momentum going into 2018.

As a reminder, during this question-and-answer session, we may make forward-looking statements 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 statement. Further discussion of these risks and cautionary information about forward-looking statements may be found in the third quarter materials posted yesterday, in the Form 10-K filed earlier this year or our Form 10-Q that was filed this morning.

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 earnings release for this quarter.

Now without further delay, we will get started. Our friends in Houston, I believe, have a parade to attend. I will turn it over to Jay for some brief opening comments. And then also present here are Wade Pursell and Herb Vogel, ready to answer your questions.

Jay?

Well, thanks, Jennifer. Thanks for pointing out the parade, too. I had forgotten about that. Good morning, everyone. Thanks for joining us. One of the benefits we're finding to prerecording our quarterly commentary and releasing it early is that we tend to get a lot of feedback on questions people have about anything we've said that might be confusing and needs to be clarified or, frankly, even questions from other people's calls that we can address.

This quarter, the question du jour appears to be about our fourth quarter production guidance coming in a little lower than our previous guidance. So if you look at the revision we made to our guidance, we lowered our full year estimate of production by 1.1 million barrels of oil equivalent, and all of that is essentially from expected lower gas and NGL production from our Eagle Ford asset. Now more than half of that number, 0.6 million BOEs is due to that great Eagle Ford JV we signed this last quarter, a fantastic deal in which we're sharing some volumes with our JV partner in exchange for improving our capital efficiency and moving more capital spending to the Permian. It's a great deal. We're really excited about it, happy to talk about it.

The remainder of that is due to temporary impacts from the storms we experienced. That number adds up to about 300,000 barrels. And a couple of expected, really small nonrecurring items of about 0.2 million barrels of oil equivalent, which are just going to happen in this quarter and will be over. So if you make those adjustments, you get right to our new guided numbers of 44.4 for the year and 10.3 for the fourth quarter.

Now obviously, the big driver of our business right now is oil rate and margin growth, and those small gas volume changes don't really have much impact on our business. But I understand that people need to understand how the numbers add up.

Now certain analysts were -- have numbers in their guidance for 4Q that are well above ours, and I never really understand how they -- how people get so far off our guidance. But I suspect they come to these numbers by making optimistic assumptions about well timing. And so as Herb and Wade discussed in our prepared remarks, we're right on track with our Permian operations, but the plan has a number of multi-well pads, I think, about 18 wells right now that are scheduled to come on late December. Most of the money -- all the money will get spent this quarter, but they may come in late December, even potentially into early January. So those wells are right on our schedule for these multi-pad developments. It's going to be lumpy here, especially at the beginning of our program, when we're ramping up big rate. And it won't contribute much to 2017 production. So that's -- I think that's probably the source of that potential disconnect with some people.

So now you've got the slight deceleration activity in the Permian. This coming from, again, from this capital we've been able to free up in the Eagle Ford. I mean, if we're bringing in an eighth rig and a fourth crew, fourth frac crew into the Permian before year-end, frankly, I think, the way you should look at this -- any investor should look at it, is it looks like we're going to have a really great start to 2018. So we're excited about that and looking forward to that.

So with that, I think we'll just open it up for questions.

(Operator Instructions) Our first question comes from Michael Glick of JPMorgan.

So I'd be remiss if I didn't ask about the PRB. Could you talk about the latest and greatest there in terms of results in the basin, how the plan should evolve into 2018 and, ultimately, how you believe that asset fits in the portfolio?

Yes, I'll tell you what -- this is Jay. Herb, do you want to talk about what we're doing right now? And I'll kind of address the more strategic one.

Yes, we're right on track with that. We had a first phase of 10 wells. We've got by 7 of them producing now, have another 3 that are in between completing and flowback. And then we're drilling on phase 2, which is another set of 10 wells, and we're on the second well of that second phase. So we're all on track with the plans and the JV partner, and we've been making great strides, particularly on the drilling progress. And then the well results have been outstanding, as we've shared last quarter.

I'll make a couple of comments on it. We get asked questions occasionally about whether those JVs, particularly the JV in the Powder, is an impediment to selling the assets or an impediment to get the deal done. That -- absolutely not. These deals are not impediments to doing deals. They're actually drivers for getting deals done. And we want to make sure that people can clearly see the value in those assets so that when we see a deal that we want to make, we're not -- there's no impediment to doing those. Let me just take a minute and talk about divestitures as a general topic. I think when we talk about potential divestitures like the Powder or even a portion of the Eagle Ford at some point, we have to remember, we currently got $1.4 billion in liquidity. We have no secured debt. We got no near-term maturities on our secured debt -- on our unsecured debt, and we're well hedged. Our business plan doesn't assume that we're going to make any further divestitures, and we don't need to make any in order to get to lower leverage levels over time. And frankly, we're moving as fast, I think, as any prudent operator would go in our Permian and the core of our Eagle Ford asset to develop those -- that acreage. So our current leverage isn't a drag on our growth. Now with that said, I understand, we all understand here the potential benefits of strengthening the balance sheet. But you only get to sell these assets once. And we're going to prioritize achieving appropriate value for those assets over speed of execution. We're working with these JVs and other things we're doing in-house here to efficiently prove up drillable inventory and value in parts of our acreage positions that we think are underappreciated. And we're going to periodically test that market, and if we can achieve a value for a property we think is attractive and appropriate, then we'll transact. And I think we've demonstrated, we're not shy about selling things, and we're going to stay very active in that effort. Now obviously, we can't give anybody assurance that any deal -- any particular deal will be done in any particular time frame, but we're going to be persistent and consistent in looking for appropriate values for this acreage at some point.

And then in the transcript, you talked about a Wolfcamp B and Lower Spraberry test in Northeastern Howard that are flowing back and performing in line with the Viper well on early time data. Can you give a bit more color on the flowback of those wells and how you drilled and completed them?

Michael, this is Herb. So yes, we're not giving a whole lot of detail out there. Obviously, next quarter, we'll have probably at least a 30-day peak on the Wolfcamp B, and we'll know better on the Lower Spraberry. But yes, they're performing right in line, but it's really early days. We're 2 weeks into this, and they were completion designs that are pretty close to our standard completion design, and they are 10,000-foot laterals on those wells.

Our next question comes from Mike Scialla of Stifel.

When you look at the results now in Howard County, both yours and competitors', can you say what you think you've derisked of your acreage there, maybe in terms of the Wolfcamp A and Lower Spraberry?

Mike, this is Herb. Yes, we're going to do that, really, in February. We're going to go over all those things we showed last January and February, where we showed the maps and where the sweet spots were and what we've confirmed so far. You're right. There were as many as 28 rigs running in Howard County. There's been a lot of derisking of multiple zones there, and we'll be sharing that in February. We didn't think it was worthwhile doing incrementally each call, so that's where we'll be.

No, that makes sense. I guess, just as a broad brush, I mean, it looks like a large percentage of your acreage at this point has essentially been derisked. Is that fair?

Well, yes. We're really pleased with all the places we've drilled that we've definitely exceeded our acquisition expectations by a large measure.

Okay. And then I know in your prepared remarks, Herb, you said that the JV agreement details are confidential. But just, I guess, in general terms there, it sounds like somebody's coming in. And are they funding essentially the -- all the drilling and completion of these wells in order to earn some interest in the properties?

Yes. It's an arrangement very similar to the one we have in the Powder River Basin, which we found to be just exceptional at improving things in a number of ways we hadn't anticipated. So very similar arrangement, but it is with a different party. I just want to make sure that everybody was clear on that. But we think they'll bring technology and they'll bring services and they'll bring, call it, funding for the joint venture area.

Can you say how much capital you're saving by going with the JV route?

Yes, that's probably one of those areas we really can't get into. When you do this, Mike, a lot of what they're doing is providing services, so it's a little hard to get to an exact [capital]. When we guide the next couple of years, we're going to put it -- we'll get it in our guidance, and you'll see it. But it will be -- it will end up being a reduction in our outspend. And that's an important aspect of it for us.

Our next question comes from Asit Sen of Bank of America Merrill Lynch.

So on the Permian LOE reduction, is this a function of higher production? Or are there other factors in play?

Yes, Asit, this is Herb. It's pretty straightforward on the Permian. We've -- a large share of our LOE is related to water handling, produced water handling in particular. And as we initially put on wells that are more remote, we're trucking a lot of water. As we build out, have larger pads, we get more and more that's put on pipe. And so as we progressively move more water to pipe, that really leads to significant LOE reduction. And we've got some ways to go in getting even more on pipe. So that's the single largest area to contribute to lower LOE. Another slight area, and that's the -- we inherited a number of vertical wells with the acquisitions, around 500. And as we've gone through them and done some work to get them up to long-term standards for us, then there's been some expense there. But that drops off over time. So those are the 2 key areas.

And on the Jester wells, just -- it looks like you stepped up the proppant loads but didn't necessarily get the productivity uplift on a IP30 per thousand foot basis. Could you comment on that, and potentially cost and spacing assumption -- spacing there?

Okay, Asit, on the Jester wells, they're higher sand loading in those locations, but they're also higher water loading. And we know that the behavior. You've got to really look at it more like after 6 months to a year rather than just looking at the IP30. We've also done some changes in chemical mixes, and we'll see how much those influence things in, say, the first year cumulative oil. So that's really what's driving Jester. Note one thing that one of those is a Wolfcamp A, and the other's a Wolfcamp B in the Jester pad. So we'll see how much communication there is between those. Even though they're 420-foot spacing on (inaudible), they are vertically separated by quite a distance.

Our next question comes from Paul Grigel of Macquarie.

I guess, just starting off on the reallocated Permian capital and realizing you guys don't want to give full '18 guidance. But how should we think about activity within the Eagle Ford? Is there still going to be activity in the Eagle Ford outside of that northern area in 2018?

Paul, yes, this is Herb again. Yes, we will continue to operate in the Eagle Ford East for our regular operations, meeting our leasehold commitments and getting some great Tier 1 gas and NGL wells. I mean, that is -- the NGL prices where they are, that really helps out our economics there. So yes, we'll be continuing there.

Okay. All right. And then, I guess, you have made the comment as well on the potential for about 400,000 of savings on locally sourced sand within the Permian. Could you explain in a little bit more detail on the testing that you've seen there? And then how has that ramped into '18? Is that early in the year? Does it kind of come in throughout the year? And then just general on what you guys see as the general service cost outlook, as things stand today, especially in the Permian.

Yes, there's several things there you put in there. So first of all, in the transcript I've gone over really on the tech spec side of things, [hope] the sand works for almost all the intervals we have in Howard County and Sweetie Peck, so we're real optimistic there. In terms of local sand capacity, there's about 2 mines currently operating with about 6 million tons per annum of capacity. There's -- underway are 3 more mines, with 10 million more tons. So we do see a big ramp up, and there's quite a few more projected after that. We are engaged heavily with sand suppliers. So when we talk about that 400,000-plus, we've got a really informed view what sand will likely cost us in the future, and we're feeling quite good that as we -- as these sand -- local sand mines ramp up, we'll be able to use an increasing percentage of local sand in our completions, and that'll achieve those savings through 2018.

And then more broadly on the service cost outlook in general right now.

So on the service cost, it's kind of -- it's pretty level. We projected a 10% increase in completions cost. And some areas were a little bit higher, and some actually dropped. And then we had some efficiency. So in aggregate, everything kind of came together at what we projected for the year, so we're pleased about that. We do see some additional room for efficiency gains that will offset whatever escalations we see. But the markets really kind of hit a nice stable place right here right now, and we'll see if that continues as we go into '18.

Our next question comes from Biju Perincheril of Susquehanna.

Great results in Howard County. I have a question about the Eagle Ford JV. The wells that you're completing -- that completed in the third quarter and the fourth quarter, were those in the original plans for this year? Or are these incremental?

Yes, Biju, this is Herb. The -- those 7 completions were in August and September. There's no other completions in the fourth quarter in the Eagle Ford, either side. And those were in our plan.

Absolutely. That's why we see the impact associated with sharing them. They were in our original plan, and as we remove that volume, that takes down our guidance.

And obviously, we were negotiating the JV arrangement over a number of months, and those completions started after the discussions commenced.

Got it. And then on the Griswold or the Iceman pilot, I know it's very early time in terms of production data, but can you say anything about how the bounded wells are performing in those 2 pilots?

Yes, that's interesting always. It's -- you always think it's going to be very simple. It's going to be -- the middle one's going to be worse than the 2 on the outside. It doesn't always turn out that way, and it's always a little bit difficult to explain. So it's mixed. Really, for drawing conclusions on spacing, we've concluded, you really need to wait 6 months to a year to really get a handle on where things are headed, and this is no different.

One of them -- one of the bounded wells is the best well in the pad so far, so it's just hard to come to.

Yes. Hard to reach a conclusion there.

Yes.

But we did show on average, and that's what we were showing in that slide, that those 8 wells that we talked about that are 420-foot spacing, and the middle ones are bounded, obviously, they're performing right in line with the previous wells that were on wider spacing for that period of time.

Got it. So do you think -- is it sort of like a 6 months or so time that we need to see if there is any separation?

Yes. The key thing is we're not just looking at production data. We've got reservoir stimulations that tell us about what kind of degradation we should expect. We have rate transit analysis that tells us how effective our completions have been. And so we can say, "Okay. Well, this well, it's performing well, but it's because of the great stimulation. And this one is performing worse because of the poorer stimulation." We have a lot of big data analysis where we actually have quite solid correlations. And we use not just our data but, actually, a vast database where we have data from trades with other parties around us. So we've got a pretty good handle. And if you can picture it, if you've got a -- call it an IP30 and -- with spacing at 1,000 feet plus. And then you've got a lot of data around 660 feet. And then you've got data at 420, down to 385, down to 330, it's not linear. So as you move from 1,000 to 660 feet, you don't see much of a reduction. As you start getting down, it drops off, but down at that 330-foot type of level, where you'll see bigger impacts. So we have a pretty good correlation on how that looks in general, but there is a range. But that's really how we look at it. And then we tell ourselves, "Okay, it looks like in this area, these wells are coming in about as we expected from that big database."

(Operator Instructions) Our next question comes from Chris Stevens of KeyBanc.

Can you just talk a little bit about some of the objectives of the Northern Eagle Ford JV that mostly just kind of testing some new enhanced completions and improving the economics of the acreage out there? And then, I mean, are you also testing some new areas? And then, I guess, what's the bias for that acreage if you are able to unlock some value? Would you look to sell that northern part of the acreage or possibly sell the entire Eagle Ford? What are the thoughts there?

Okay. Chris, I'll start this, and then Jay will jump in on a number of things you've asked. First of all, so the Eagle Ford North, it's pretty sparsely drilled, so we see a lot of inventory potential there. And we started seeing quite a few wells just to the north of us, where the performance was increasingly getting better and better. And we started to put together an opportunity list of things that we were seeing that would improve the economics considerably, but it would take some time to sort out which ones would work the best and which ones we should try first. And clearly, that would cost the money to -- and there would be some risk dollars associated with it. So we did identify some potential partners, and one partner in particular brought in several things that they saw, and we've applied just a few of those in these first wells, and you can see the performance is great. And we have a whole list of a lot of the opportunities. And I won't belabor these, but this includes stage spacing, a number of chemical things. But the fundamental thing is you can get a lot more data on your wells, if you're willing to spend the money to get the data, and that will inform you a lot about the completion design. So that's what we saw. So bottom line is we see a way to get economic inventory over a large acreage. And you've got to put a bit to it, and you've got to try the different completions to see the results, and that's what we're doing.

So let me -- Chris, this is Jay. Let me address the overall strategic issue a little bit. So what we're doing with these JVs and what we're doing on what we would call probably our -- outside our core development areas, which is really the Southern Eagle Ford position and our Midland Basin area, where we have very, very high returns. So we would call those top-tier assets. The strategy of the company is to own top-tier assets and to develop top-tier inventory. So what we're doing in these areas, both in the Powder and in this Northern Eagle Ford area, is we're trying to understand really for ourselves, is this top-tier inventory? If you look back at both these areas over the last couple of years, we hadn't done a lot of -- hadn't had a lot of activity in them, and the activity we had was a few years ago when we were either drilling in the Eagle Ford probably on too tight of spacing, in the Powder, we weren't using very big frac jobs. We just had never really put our best foot forward in understanding, can we make this into truly top-tier inventory? Now if it is, we already own the acreage, so that would be awesome, right? We develop a bunch of top-tier inventory in acreage we already own. It's great, full cycle economics, all that stuff makes a ton of sense. And we need inventory in the long term, and we were going to get cash flow positive here in a few years, and we need top-tier inventory, so that would be great. On the other hand, if we look at this over time and we say, okay, we've done what we know we can do, we've made great wells, but they're just not going to compete with the kind of things that we have in our Permian inventory, for example. Then I think you look at that and say that could be the kind of thing that could really help us de-lever the balance sheet. And we're not shy about selling stuff. I mean, we will sell things if it makes sense to do it. If it doesn't fit with us and it has a lot of value to someone else, we're going to do that. And that -- and I'll put that -- anything we own in that category. We're activists here. We're going to do something if it looks to us like we can make our business better by selling a piece of it, we're going to do that. But we're going to do it once we understand it and once we know that we can demonstrate what that value is, so we can get a decent -- the right value for it when we sell it. I think that's about as clear as I can be.

That is appreciated, definitely appreciate the color there. Maybe I can just move over the Powder River Basin. Any update there in terms of when you might test the Niobrara formation? It seems like that could be a pretty big upside driver of value for the asset. And then on some of the newer wells that you've drilled out there, it looks like the Biscuit well is showing some pretty nice productivity uplifts relative to some of the older wells out there. I guess you probably have 6 or 7 months of data on some of these wells. I mean, do you think the economics could kind of compete with the Permian at this point? Or is there still a pretty wide gap there?

Chris, let me go first to Niobrara. So obviously, we've been working in the Niobrara pretty hard, but we haven't lined out a specific location or permitted a Niobrara well there yet, but we do want to get that tested soon. We have noted that there's quite a few Niobrara permits just off our acreage, so we know the industry will be delineating around it, and that's always beneficial. You learn a lot from that. On the -- some of the Frontier wells and Shannon wells in Powder, yes, we're real pleased with the way they're coming. And we obviously have competitive people here, and the Powder River Basin team never hesitates to show me how their wells are doing as well as the Permian wells. So if we can get the cost [set at] Permian level, and there's no doubt they have dropped the cost significantly, then they could be competitive. So we're really liking what we're seeing. We're really pleased with the JV and what's it's brought to the wells. I'm not going to say yet where they're going to rank in our full portfolio, but we're encouraged with what we see so far.

And any update on what the latest well costs are out there at this point?

Well, it's interesting, because as part of this JV, there's considerable data acquisition going on in order to enable the improvement in the subsequent wells. So it's hard to pull that data gathering out. But I will say it's significantly down from where we were a year and 2 years ago.

Our next question comes from Stark Remeny of RBC.

I just have a quick follow-up on the PRB. Obviously, you guys are seeing the same thing a lot of other players are seeing, and it looks like very impressive results so far. Can you kind of give us an idea of when the asset would start attracting SM-operated capital, assuming a sale is not transacted?

Well, if you think about the JV we have in place -- Herb, make sure I get this right, I think we basically -- there's about a year -- not quite a year left to run. We're on the -- we're completing like the eighth or ninth well in the first phase, and we're drilling on the first couple in the second phase. So it would probably be at least the end of next year before we would start to put substantial capital in. Obviously, I mean, Herb can maybe comment. This thing is starting to look like it could compete, so my hope is that we get to a decision point on putting our own money in there, about the same time, frankly, that we get to a point where we have free cash flow. And it works out great in our business plan from that standpoint. Or we'll go to the point where, hey, it's not going to quite get there, and we've got a lot to do in the Permian that we can still accelerate on and we can make a decision in a different direction. But I don't think you'll see a lot of our own money. You may see us put money into the Niobrara here in a test mode, kind of exploration mode. But other than that, you probably won't see a lot of our own capital going in there, at least in the next 12 months.

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And so I guess, is the expectation for potential improvement being weighted on the capital side or on the well performance side or just some combination?

Stark, it's both. I mean, we're really driving the cost down, and we're also working to get the well performance up. So we're -- we'll -- we don't stop at anything there.

Our next question comes from Michael McAllister of MUFG.

My question is -- deals with the -- can you talk a little bit about the Viper well? It's been on for a while, and it's held up very robustly, and if it has something to do with the stage count?

Michael, this is Herb. Yes, we've done a number of tests now with increasing stage counts for 10,000-foot laterals from 67 to 80 some. And we think it'd probably take a little bit longer to see be a big benefit of that increased stage count. Obviously, we don't have an offset direct (inaudible) yet, where we can tell that. But no, I wouldn't attribute it to fully the stage count. I think we're pleased with the rock in that location, and we've talked before about how there's -- in that area, there's tight carbonate, porous carbonate and mudrock. And where we have porous carbonate, the wells do perform well. And a lot of people have missed that before, and that's really what we're seeing in a lot of the eastern part of our acreage position that's really benefited us. So not -- I wouldn't attribute that solely to the additional stages.

So it's a function of the rock.

Yes, coupled with a good completion design.

It is a great completion design. And that design is essentially -- Herb, can you just comment on how we're looking at stage count in particular, kind of how many we're pumping at various stage levels to kind of get an idea on that?

So typically, the key thing here is, we have some models, and then we calibrate them. And if we're doing a 3-well pad, say, we typically will run the same completion design in the middle and one edge well, and then we'll run an improvement test on the other one so that we can see on either side of a bounded well how much difference it makes. So that way, we can really calibrate. So when reach a conclusion, we've got some pretty firm ideas. And we don't do it in just one location. We'll probably do it in 4 before we'll draw a conclusion, because you want to normalize out what are the influences with the rock. There's some things that always happen that are slightly different in wells. So that's -- we're very systematic about assessing completion design changes.

And that would be the approach to the Sundown pad?

Yes. So the Sundown pad, so obviously, one is a Wolfcamp B, and the other is a Lower Spraberry. And it's just up from -- just north of Viper. So those are really, I'll call those delineation wells. They're our first wells out there at that edge. And our confidence, obviously, has increased. We've already got them online. But also because of those wells that another operator drilled just to the west of our acreage that are both Lower Spraberry -- well, there's the Lower Spraberry in Wolfcamp A, and then we have that Apache Eastland well in the Wolfcamp B that's a good well, although with a short lateral.

This concludes our question-and-answer session. I would like to turn the conference back over to Jay Ottoson for any closing remarks.

Well, I don't know if there's anybody left on the call, but we really appreciate you being with us this morning. And as Jennifer started in our introduction, we're really happy with our results and, certainly, the direction the company is going from a cash flow standpoint margins, just a whole lot of things are going well for us right now. And frankly, we look forward to a big first quarter '18 and to a really solid fourth quarter here. So thanks again, and we look forward to seeing you around the conference circuit. Thanks. Bye-bye.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.