Good day, everyone, and welcome to the SM Energy 2017 Results and 2018 Operating Plan Q&A Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. And please note that this event is being recorded. I would now like to turn the conference over to David Copeland, General Counsel. Please go ahead.

Thank you, William, and thanks you all for joining us this morning by telephone and online. 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 to our website for this call, and the Risk Factors section of our Form 10-K that was just filed. 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.

Thank you, David. Well, thank you, everyone, for joining us. I recognize that we released a lot of material last night, and there's a lot there to digest. So I very much appreciate you taking the time to call in today. I do have one introductory comment before I open the floor for questions. Over the past year or so, I've spent a lot of time talking to people who've been disillusioned with investing in the oil and gas space, because they believe industry management teams don't really care much about making high returns on capital. My response to that concern is always that we agree with that. And that SM Energy's singular focus on achieving top-tier returns as a measure of success in our business currently has us on a path of demonstrating a very high rate of change in the improvement of our business relative to our peers. I listened to our recorded call notes again. And I'm sure we must have said 50 times that we focus on achieving high returns as measured by growth in cash flow per debt adjusted share. And that is how we have built our business plan, a plan that achieves about a 35% cash flow per debt adjusted share growth rate over the next several years. To be clear, production is an output from that planning process, not an input. We have never had a production growth rate metric in our long-term incentive plans here at SM. And even though we've averaged over a 98.5% approval rate on our say-on-pay votes over the last five years, we are going to modify our long-term incentive plan metrics this year to explicitly include cash flow growth per debt adjusted share as a key performance measurement. We'll be disclosing more about that in our upcoming proxy. So with that I'll open the floor for questions.

Thank you. We will now begin the question-and-answer session. And our first questioner today will be Michael Glick with JPMorgan. Please go ahead.

Good morning. Hey, Jay, could you talk a bit about the rationale behind the deceleration in the rig and crew count in the Permian as you move through the year? And perhaps its implications on 2019?

Michael, this is Herb. I'll take that one. So you're probably aware we've been getting quite a bit more efficient on our rig rates, drilling, how fast we're drilling. And, for example, what we would drill with 11 rigs in 2016, we can do with 8.5 rigs this year. And we also are going to large pads with co-development. And by doing that, we wind up with a large number of DUCs at a certain time. And then we complete them and we bring them all online pretty quickly. So what you'll see is a large increase in the DUC count at the end of 2018. And shortly thereafter in 2019, we bring those all online. So we'll be spending completion dollars in 2018 for a bunch of wells that come on in 2019. I think – does that answer your question for you?

Yeah, I think so. And then also, Herb, maybe you could talk about that Sundown pad and how well performance, particularly in the Wolfcamp B, is comparing to that Viper well?

Okay. So it's still relatively early compared to the Viper experience. But the IP was quite good on that Wolfcamp B. It reaffirmed our views from that Eastland well that Apache had drilled just to the southwest of there. So it's on that same trend which we see, which is relatively low decline. We'll see where it goes, but it's a strong well.

Got it. And then lastly, could you talk about any non-core asset sales, such as Halff East out there?

Well, we look at the opportunity to core up all the time. We are exploring the idea of selling Halff East. Don't know if we'll get a number that we like yet. And we'll let you know where that goes. We're kind of in that exploration phase at this point.

Got you. Okay. Thank you.

Thank you.

And our next questioner today would be Brad Heffern with RBC Capital. Please go ahead.

Hi, everyone. Good morning. Just as a follow-on, on the Sundown wells, it looked like they used a tighter stage spacing than the other new Howard County well results. Can you talk about why you did that and whether you think it had a meaningful impact on production?

Brad. Yeah, you're right. We went with tighter stage spacing there, I think probably around 84 – 82 to 84 stages in that well compared to – so effectively a 125-foot stage spacing versus our standard 167-foot. We've been trying that in a number of places. So we're trying to do direct offset comparisons in some cases to see is the incremental investment in the additional stages worth it. So we're still in the testing stage on that and those Sundown wells we applied it there, we also had that in the Viper well.

Okay. Got it. And then on the water handling front, you guys are obviously making some big investments this year. Understanding that you gave some color around LOE sort of declining throughout the year as those come online, can you give any sort of quantification as to what the scale of the LOE decrease is from that?

No, I don't think we've really prepared to do that. Obviously we're in the core areas where we're building out that infrastructure and then there's other areas where we'll still be using third party. But yeah, I wouldn't put a number on that yet. We're just in the building phase right now.

Okay. And then finally can you just talk through service costs a little bit? I know the budget assumes 10% to 15% increase Have we seen any sort of stabilization in the market and just how is capacity looking in general?

So first of all, let me address the capacity question first. So, we've not had any issues with capacity. We've got vendors lined out and we've been using the same ones over and over again. They know our program. They know what to expect so it can work quite effectively for them, very efficient for them. That goes to our rigs and our completion crews and then some of the ancillary services like cementing and logging. So, we've baked in a certain amount of escalation. Some of it is, where we have no escalation, we've got firm contracts and then some there's some linkage to prices where there's escalation based on certain price parameters and we know those will be coming in, we bake those in. So bottom line is availability looks good for us. And the escalation we've baked in, a lot of its relatively firm for the first half of the year and then we'll see where the second half goes.

Where prices go.

Yeah.

Okay. Thanks.

And our next questioner today will be Biju Perincheril with Susquehanna. Please go ahead.

Hi, good morning. Can you talk a little bit about the Griswold pilot and the performance of those wells? And how you're thinking about spacing in the Wolfcamp A on that southeast part of your acreage?

Biju, will you repeat the first part of that?

Yeah. I was wondering if you could talk about Griswold pilot and the performance of those wells? And how you are thinking about development spacing?

Okay. So the Griswold, there's a few wells over there in that area and those are on the periphery. And there's a number that we drilled over there for acreage holding. The real pilot areas for where we're down spacing, that's like the Iceman pad would be an example, where we've gone down to 420-foot spacing there and stacked Wolfcamp A over – Lower Spraberry over Wolfcamp A. So we do have a spacing model that we're using, so typically 500 to 660 feet in the Wolfcamp A. That's really what we've determined is the optimal, based on all the work we've done in both Sweetie Peck and Rock Ridge. Is there something specific about the Griswold you wanted to know?

No, I was wondering, I thought that was a 420-foot spacing test. Maybe I misunderstood that.

Yeah. And the Griswold, let me just pull up the results there. Well, actually, what I'll do is I'll have Jennifer get back to you on that one.

Okay. That's good. Thank you.

And our next questioner today will be Chris Stevens with KeyBanc. Please go ahead.

Hey. Good morning, guys. You gave us the 2018 rig cadence over the course of the year. You're going to enter 2019 with seven rigs in the Permian, one in the Eagle Ford. How does that activity trend through 2019? Do you kind of keep that rig count flat there? And I guess how much CapEx or, directionally, how does that look when you're assuming that you'll be free cash flow neutral by mid-2019?

Yeah. Our assumption for 2019 is we keep the activity relatively flattish. But you just have to watch the DUC count versus the rig count, as we get more efficient that can influence things considerably. But we have not provided capital guidance on that one.

Okay.

Directionally, it will be lower than 2018.

Okay. And so I guess how many DUCs are you going to enter 2019 with? And how many of those will you be working down. I mean are you going to complete more wells in 2019 than in 2018?

I think the DUC count we provided at end of December is around 110 to 115.

That's at slide 34.

Slide 34.

Where we give it by month, and you can see the build at the end of the year.

Okay. And so are you going to work that down pretty significantly in 2019?

Yeah. This is where it gets real lumpy. As we go to these 25-well type of co-development, you see 25 wells come on in a very short period of time. So then your DUC count drops within a month by 25 wells. And then you build it up again. And that's just what we've determined is very much the optimal way of developing.

Okay. Got it. And just lastly for me, did you incorporate the in-basin sand cost savings into the 2018 CapEx budget? Or is there maybe some downside if that comes in at some point?

Yeah. There is some of it. I guess the way to look at it is, I just checked, and last month we ran about 20% local sand in our completion. And by the end of the year, we hope to get to around 80%. So look for the year what the actual savings will be will depend on how quickly those local sand mines come on. And we indicated that U.S. Silica has told us first quarter and third quarter, and they're on track for that. So that's really – yes, there is an opportunity if we get more local sand to reduce further. But we've got something that's very reasonable baked into that plan.

Okay, got it. Appreciate it.

And our next questioner today will be Nitin Kumar with Deutsche Bank. Please go ahead.

Good morning, guys. If I can just go back to that slide 34, as you exit this year, you're building about 30 additional DUCs, but you're reducing the rig count. What's a normalized DUC count for your rig cadence right now?

Okay. That's a tough one. I usually think of it in terms of frac spreads per rig. And that's usually the way and basically you can see we run about 2 to 1, so 2 rigs per frac spread. And then how it actually moves through time is really pad dependent. If we do two-well pads, they come on pretty quickly. If we do six-well and we do a number of six-wells together to co-develop, that's a different story.

I'm sorry, what I meant to ask – what I'm trying to say is how many DUCs is normal inventory? Let's say you're running 7 rigs through 2019, how many DUCs would you hold in normal inventory given normal operations?

I think you just run an average line through what we've got there and that would be a pretty good indicator.

Okay. Can you talk about – you mentioned the Austin Chalk in the Eagle Ford. What are you seeing there and kind of what are you looking for?

Yeah, there are two things on the Austin Chalk. First, we know a lot of other operators in the Eagle Ford have gone and test the Austin Chalk and have some great results. Second piece of information is that we had one Eagle Ford well that was initially in the Eagle Ford for a good portion of the lateral, but then went up into the Austin Chalk and we find that the condensate yields and NGL yields are higher in the Austin Chalk. So that's an attractive economic proposition, deliverability look good too. So we'll be testing that. It would be a potential big inventory add for us if we could add another layer of Austin Chalk across our full acreage position.

Would it command capital in 2019 and 2020 if you had success?

Too early to say.

Great, thank you.

Thank you.

And our next question will be Gregg Brody with Bank of America. Please go ahead.

Good morning, guys.

Good morning.

With your PRB sale, you noted that you retain 20% of your acreage. What's your plan with that and is that something that you would consider developing down the line?

This is Javan. I think our plan would be to exit that acreage over time. Most of that acreage that's remaining is small dribs and drabs of things in mineral interests, small interest in other wells. It's not a big cohesive thing that we can really develop. So I think it would probably – most of it would probably get sold in auction processes or in small processes. And it'll take quite a bit of time. None of it's operated to any significant extent. So it wouldn't impact our ability to exit operationally.

That's helpful. And then just other than the Bakken, what else is there that you could – that you're considering selling? You kind of hinted at continuing that with whatever's left and what else is...

Well. This was mentioned earlier in the call. We're exploring the sale of Halff East, which is a non-operated property we have in the Permian. We'll look over time. We're not shy about selling things. And I think we're getting to the point where a lot of what we own has great inventory in it. And that makes all those decisions more difficult. But certainly, we're going to continue looking at our portfolio every year and deciding whether it fits. Our objective is to own top tier assets. And if we can find ways to get better assets, we're always going to look for opportunities to trade up or do whatever we need to do.

Got it. Thank you very much, guys.

Thank you.

And our next questioner today will be Chris Stevens with KeyBanc. Please go ahead.

Hey. Thanks again for letting me ask another one here. I guess how much additional facility in water infrastructure CapEx should we expect in 2019? And I guess is that something you plan to keep in-house? Or could that be potentially monetized at some point?

Chris, Yeah. This is Herb. So for 2019 – well, first let's get our backbone going in 2018. 2019, we'll have most of the backbone in there. And it'll just be a matter of whether we extend it from there. So, no, we haven't really looked beyond that. And there's always the opportunity to sell a water system if it makes sense.

Okay. So it's not necessarily something that you built it with the intention of selling. It's just something that maybe opportunistically you would evaluate?

Yeah. Chris, this is Javan. I mean, we've done this before. We built water systems in the Bakken and then sold them and kind of had a leaseback arrangement. And I think that makes sense to us. At this point in the development, having control of these assets, has a lot to do with maintaining schedule. We have great relationships with the landowners and everything we need to build these out. It just makes sense to us. You run the economics, it's just really a compelling story to go ahead and build these ourselves. And we can make the decision here in a year or two about, okay, do we need to continue to own those? Or can we make a turn here by passing that on to someone else? So we'll make that decision. We can go either way. It's certainly an opportunity. I think it's going to create a lot of economic value for us. And that's why we're willing to spend the capital over the next 12 months.

Okay. Got it. And I guess in terms of the spacing, the wellbore spacing, how do you guys plan to go and develop Howard County in 2018? Is it going to be all 660-foot spacing? Or are you going to do some 500-foot spacing on a portion of the acreage? And I guess also if you can just kind of talk about that in regards to your inventory at year end 2017, does that include anything on tighter than 660-foot spacing?

Yeah, Chris. I will say, we've got the – slide 33 shows kind of some of the assumptions. But I'll just go over a little bit more color on that. So yeah, typically in the Wolfcamp A, we're going to be between 513- and 660-foot spacing. There's some of the Wolfcamp B further to the east we'll be going to wider spacing, because it makes sense there. And then in Sweetie Peck we'll still be doing some 420s. And typically the Lower Spraberry in Sweetie Peck will be 420- to 513-foot spacing. And that's just because of how thick Lower Spraberry is over there. Lower Spraberry will vary between 660 and 1,320 feet in the RockStar area.

Okay, got it. And just lastly from me, you guys obviously seeing a lot of efficiency gains out there. What should we assume now for how many wells a rig can now drill in a year?

Okay. Here, I'll do kind of the reverse. You can figure out the math here. We have a record well of – I believe we did one 10,000-foot lateral spud to rig release in 12.5 days. That's the record, but the average would be a little bit longer than that. So call it about – yeah, last 12 pads averaged 18.5 days from spud of the first well on the pad to rig release on the last well. So that's with 10,000-foot wells. So you can figure that's about 20 wells per rig.

Okay. Got it. Appreciate all the color, guys. Thanks.

When you see the – if you can get 18.5 days down to 12.5 days, that's a lot of efficiency gain.

And this will conclude our question-and-answer session. I would now like to turn the conference back over to Jay Ottoson for any closing remarks.

Well again, I just want to thank everybody for taking time today. We know it's a very busy day for you and we're happy, Jennifer is always happy to answer questions and we'll be happy to follow up on those. So thank you very much and have a great week.

And the conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.