Good day, ladies and gentlemen, and welcome to the SM Energy 4Q Year 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. As a reminder, today's conference is being recorded. I would now like to turn the call over to Mr. David Copeland, General Counsel. Sir, you may begin.

Thank you, Chelsea. Good morning to all joining us by telephone and online for SM Energy's fourth quarter and full year 2016 earnings conference call and operations update. 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 afternoon, the presentation posted on our website for this call and the Risk Factors section of our Form 10-K that was filed this year. 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 press release from yesterday. Other company officials on the call this morning 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, Senior Director-Investor Relations. I'll now turn the call over to Jay.

Well, thank you, David. Good morning, everyone, and thanks for being with us today. I think everybody who has followed us would agree that we're a very different company than we were a year ago. There's an illustration of that on slide 3 which shows you a summary of all the transactions we accomplished since the middle of last year. In everything we've done, our objective has been to build a strong and resilient company that's a premier operator of top-tier assets, and by doing that, to put ourselves on a path to deliver long-term differential performance for our shareholders. It has been incredibly exciting to be part of this transformation. But it's been even more exciting putting together our plans now for the next three years and just looking at that performance that we believe that we can now deliver. And that's what we're going to talk about this morning. So with that, I'm going to turn the call over to Wade and Herb so they can run through our plans. Wade.

Thanks, Jay. Good morning, everyone. Yeah, I'm very excited to share with you the specifics of our three-year plan this morning. Let me first say that in regards to the fourth quarter and full-year results, I think the press release and 10-K provide more than ample discussion in detail. So I'll not spend any time on that today. I'm going to focus on the future this morning and walk through the three-year plan which we're so excited about. So let's get started on slide 4 with a preview. The reason we're so excited about this plan is pretty simple. We're going to be generating astounding production growth and arguably the best highest margin basin in the country. So we're talking about a compounded annual growth rate in the Midland Basin approaching 100% over the next three years. By the time we get to 2019 as a company, we'll be generating significantly higher margins even in a flat oil price environment. We'll be growing year-over-year production in 2019 at least 25% within cash flow and have a strong balance sheet with around 2 times leverage. It's hard for me to imagine that not driving differential returns for our shareholders and that's our objective. Obviously, you can't have a three-year plan without a first year. So our four major priorities in 2017 will be. First, we'll be accelerating our activities in the Midland Basin and doing the groundwork to prepare for further acceleration in 2018. This means that we will focus much of our effort in 2017 on completion and spacing optimization testing, getting it ready for the high-density development. Herb's going to get into this later. Second, we'll be strictly prioritizing our capital spending on our top-tier Midland Basin asset and our top-tier operated Eagle Ford wells. Third, we expect to…

Thanks, Wade, and good morning to everyone on the call. Wade did a nice job laying out the step-change, production growth and margin expansion we see in each of 2018 and 2019, that in turn generating a doubling of cash flows from 2017 to 2019 under our plan assumptions. I'm going to speak now to the nuts and bolts of our 2017 operating program that really position us for that trajectory. There are really four key objectives underlying our 2017 program. First, we're going to drive aggressive growth in the Midland Basin, which in turn better balances the portfolio in terms of commodity mix and drives margin expansion. As shown in slide 12, our 2017 capital program allocates approximately 80% of total capital spend to the Midland Basin. Second, we'll be focusing Midland Basin capital investment on drivers of value creation, factors that optimize well performance, recovered resource and NPV per section. Third, we'll position the company to run a much larger, optimally-designed drilling program in 2018 and beyond. And then fourth, of course, we'll be building reserves and inventory. So today, what I'm going to cover is the individual objectives of each of the Eagle Ford and Midland Basin programs, along with an update on recent well results. I'll then go over well economics behind our 2017 program where you'll see the top-tier returns from both the Midland Basin and from the Eagle Ford programs. And finally, I'll discuss our views of inventory including progress already made in the Midland Basin. So turning to slide 13, let's start with the Eagle Ford, since it deserves some of the limelight. Here, we're going to focus on completing high-return wells. The program includes running one rig through most of the year with the second added in September. We plan to drill…

Well, thanks, Herb. Wow, right. You look at this presentation, and I've seen it a number of times, and I just can't get over how big a difference this is from a year ago or two years ago in terms of just everything about our company. We've got a solid plan for 2017. It's really focused on maximizing value and setting ourselves up for this big growth trajectory that we're on, really the next big step in the transformation of the company. We'll get some of this noise behind us associated with all the asset sales. Then, over the next several years, even in a flat oil price environment, we're going to rapidly grow high-margin production that's going to accelerate our cash flow growth. As we said, I'm doubling cash flow over the next couple of years. And that propels us to a position where we'll be growing rapidly within our cash flow with a strong balance sheet. All that is made possible by this much improved portfolio and we're very confident that we can continue to grow our economic inventory. Now, I don't know how you can't be excited about the future of this company. I've just never been more convinced than I am today that we're on the right path to create differential value for our shareholders. So with that, we'll take your questions.

And our first question comes from the line of Welles Fitzpatrick with Johnson Rice. Your line is now open. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Hey. Good morning.

Hey, Welles. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Herb, I think you said that 25% of the spending was going to be in the Lower Spraberry and other. Does that imply that you guys are looking at doing a Middle Spraberry or a Wolf C test this year?

So, Welles, just on that percentage, those were of the completion. That's the completion count, not the dollars (27:26). And you're right, 25% across Sweetie Peck and the RockStar area. That's 25% in Lower Spraberry. And then, the question is whether we've got others. We're going to be getting a lot of data in other zones. And we haven't finalized when we'll actually get completions done at the back end of the year when we get the data from the data acquisition program we've got laid out. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Okay, perfect. And then on slide 18, on the Eagle Ford East returns, could you give any indication? I know it's preliminary, but what that 60% might move to with the 10,000-foot laterals? I mean, is that going to be a significant bump to those IRRs?

Okay. So the 60% is the – are you talking about the returns, IRR? Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Yeah, that's right.

Yeah. I wouldn't venture a guess on that one yet. We'll put the 10,000-foot laterals out there, but we know there is a scale-up factor that's pretty substantial when we go from 7,600 to 10,000 foot in other areas. So generally, it's almost one-for-one on the contribution for IPs and EURs as you go longer. When you start getting into the 10,000 foot, we just have to confirm that that's true. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Okay, perfect. And one last one and this might be a little Q2. But on slide 9, kind of looking at that bar chart, should we take that as soft guidance that you guys are looking for some plus or minus $450 million for Divide?

We're not giving guidance on that. Obviously, we're not going to sell it unless we get something significantly higher than our leverage. And you know what the cash flows roughly are there. So we don't like to quote numbers in this sale process. What's been exciting, we've clearly realized more in these sale processes than I think most people thought we would and probably more than we thought we would. There's clearly an appetite for these and these are good assets that have drillable inventory in them. They just don't fit now in our much improved portfolio and I think that's the key thing here. We just looked at it, and decided based on what we have to drill, these assets will not attract capital from us, but they will attract capital from a lot of people and they're great assets for startup companies. And that's the kind of people we would expect to be interested in it. Welles W. Fitzpatrick - Johnson Rice & Co. LLC: Yeah. It makes sense, especially with the big jump up in returns in the legacy Eagle Ford. Well, congrats and thanks.

Thank you. And our next question comes from the line of Jeb Bachmann with Scotia Howard Weil. Your line is now open.

Good morning, everyone.

Good morning.

Good morning, Jeb.

Just a couple of quick ones, mostly on Howard here. Just I'm looking at the DUC count and kind of where you guys are building towards the end of this year. It looks like, as you mentioned, the DUC's going to be going down in the Eagle Ford, so it mean it'd be going up in the Permian. Just curious if that increase in the DUC count in the Permian is really infrastructure-driven, just a lack of takeaway or the need to build out at this point?

No. Jeb, this is Herb. The driver of that is the ramp-up in the rig count when we're going to six-well pads. And as we get that further in 2017, there's going to be more and more six-well pads. So as you can imagine, to drill up a six-well pad takes about 120 days. So you got six wells. If you have three or four rigs running on six-well pads, you can see why the DUC count really increases. And that happens as you ramp up rig count.

Okay. So I guess -

There's no infrastructure constraint, whatsoever. All we have to do is put the tank batteries in place not just on a schedule to put those tank batteries in place.

Okay, great.

...infrastructure there.

Okay. And the second one. I was just kind of looking at – if you can remind us where the drilling commitments are in Howard. And I guess, are you guys going to do any work on that northeast acreage this year?

Okay. Well, let me just say that the commitments there – it's a large lease program out there. So they'd have varying timings on when we have to drill on the different leases and there is different ways. In some cases, you can extend. But generally, we've laid that out with our expiry program on the leases. But I'm glad you asked about that northeast block. And we've been surprised how much attention it gets for – it's only 14,000 net acres. So that's around 15% of our Midland Basin position. It's a lower working – quite a bit of it is actually non-op also. So we risked that area quite a bit more heavily in the acquisition because there's fewer horizontal wells as I showed on those January 31 calls. So what we're really trying do is maximize our value and our returns throughout our entire program. So yeah, we'll have the Viper well, which you guys are aware of. And that'll be completed over the next several months. And then we'll have a couple more wells there by the end of the year. But our focus again is on returns and doing a logical program through all the intervals and confirming the completion design throughout.

Thought I'd just note there's a good Wolfcamp B well right in the middle of the acreage. And people tend to just ignore it for some reason or another. I don't really understand that. So we'll be testing at several different intervals there.

Yeah. That's actually an Eastland well, which is a short lateral, a little bit older completion design and still had a great (33:14) and it's actually got a nice decline too.

All right. I appreciate it, guys.

Thank you. And our next question comes from the line of David Tameron with Wells Fargo. Your line is now open.

Good morning.

Hey, David.

Can you just help me out – the Eagle Ford completions and maybe you mentioned it and I missed it. But kind of what does a typical job look like now? I know you talked about the longer laterals, but what does a typical completion job look like in the Eagle Ford?

Okay, yeah. For the Eagle Ford, in the East, really it's 8,000-foot laterals. On the West, it'll be 10,000-foot laterals, 2,000 pounds per foot of sand loading. And we'll do a few up at 2,500. And then the key change is stage spacing using mechanical diversion down to the 150-foot level. And we'll be trying a little bit even tighter than that and a little bit wider than that. But that's the fundamentals behind what we're doing.

Okay. And is that – I know the longer – is that a change from what you have been doing or – like let's just say in the last quarter or so?

Since the last quarter? No, those wells that I showed you, the ones in orange on that map, half of them are at the 150-foot stage spacing and half are at 300-foot stage spacing with diverters, chemical diverters.

Okay, that's it.

But they're at that 2,000 pound per foot level.

Okay. And then back to the – I guess thinking about the corporate big picture, you guys mentioned – I think you mentioned 25% within cash flow in 2019.

Yes.

What price deck are you guys assuming for that and -

That's basically strip.

Yeah, that's -

That's strip, okay. And then is there any – go ahead.

Hold on, David. Let's let Wade answer to make sure -

Yeah.

The only thing I'd say to that, Dave, is, A, is that a recent strip; and b, make sure you heard the words at least 25%.

No, that's helpful. That's good. So do you guys have any desire to hedge, to lock anything in 2018-2019?

Well, we certainly look at 2018 and 2019 as part of our regular hedging program. So the answer is, yes, maybe. The further out we go, a flat strip is a little more risky I think because cost could go up when you're talking that far away if oil prices go up. But we certainly look at it. And with respect to the bases in the Midland, we're certainly keen to look at that as well.

Okay. And then last question, whoever wants to take this. There's obviously concern from what everybody is calling the new entrants into the Permian. Yourselves and some of your competitors that have recently – well, they've made some big acquisition purchases in 2016. And there is some concern that when you go to ramp your program mid-year, your breadth of service capacity won't be there or you're last in line or however you want to phrase it. I'm sure you guys have heard that question time and time again. Can you address how you're thinking about that over the next year, kind of the hurdles for you guys ramping in the basin?

Yeah, David. This is Herb. First of all, you know what, we're not new in the basin, right. We've been there for over a decade and we have great contracts with key suppliers. So you just step through every single area, the rigs, the completion, the frac spreads and the facilities, the steel, the tanks, that sort of thing; we've got schedules laid out there. They're aware of what our ramp-up plans are. We're engaging on a continuous basis. We're in the community, right. So we're way ahead of it in terms of making sure we got everything in place. And you could see how optimally we ramped up so far. And we work with several different providers where it's not all being done with one rig company. It's not all being done with one frac company. So I think you'll see companies really like working with our guys because they've got a great program. You guys want to add anything else?

No, it's not – Dave, I understand why you asked the question and I think it's not an unreasonable question. But we've got a great program. We have a great reputation down there and it's not a concern.

Yeah, no. It's a perception that's out there, Jay, obviously. So I just wanted to -

Sure. And again, I understand it. I understand why people ask the question. But I think people need to understand. We've been there a long time. We know everybody. We've been preparing for a while for this. And we wouldn't be putting these big numbers out here if we didn't think we could do it because that would be really dumb. So we really feel like we can do this.

All right. Thanks for the color.

Thank you. And our next question comes from the line of Chris Stevens with KeyBanc. Your line is now open.

Hey. Good morning, guys. Just had a question on the Viper well. Is that first one on Wolfcamp A? And I noticed you guys permeated another well right next to it. Is that going to test the Lower Spraberry so you basically have all three zones sort of de-risked this year? And did I hear you correctly that the first Viper well will be completed here in the next couple of months?

Yeah. Chris, this is Herb. So yeah, the Viper well is a Wolfcamp A well. And yeah, by the end of the year, we do plan to have Lower Spraberry and Wolfcamp B tests out there. And Jay mentioned earlier for one of the questions that Apache Eastland well is right there. We also have – just to the west, there's some great wells operated by Legacy that were Lower Spraberry and Wolfcamp A. And then you're probably aware there's a couple of other wells from another offset operator just to the west of our acreage. And then there is Hannathon drilling to the southeast. And I showed in January 31 a map of where all the rigs are in Howard County. And you can just see how far operators are expanding just based on the mapping and all the additional data that people have out there. I think that cover all of them.

Yeah. Chris, we're not going to get into too much detail about exactly where we're drilling because frankly there's still open acreage in some of these units. And if you start putting sticks on a map for people, then you just create competition. So we're not going to do that. But we're going to get a good spread of tests on that acreage by year-end and that's at appropriate level of interest considering how we valued this acreage when we got into it.

Understood. So the inventory in Howard mostly based on 660-foot spacing. What testing are you going to do on the down-spacing this year? I guess how tight will you test and is it going to be mostly in areas that are currently de-risked?

Yeah. Chris, let me just say that on the spacing side, where the sections like in Wolfcamp A are quite thick, we stagger them, right. So the spacing, on a plan view, could look really tight. And then, within an individual phases, they'd be wider. But we're not really sharing what our plans are there. Obviously, that's one of the key competitive differences, especially when you're out there on a leasing program. But we test those and we look at how they're doing and then we modify the design accordingly. But we're not elaborating on which ones are, what spacing, probably because the thicknesses vary and how much staggering we're doing in our wells.

Okay. And probably last quarter, you were testing 400-foot spacing over at Sweetie Peck. Is the inventory updated for that tighter spacing at this point over there?

Yeah. So for the Rock Ridge in that economic inventory or the RockStar acreage, it all assumes simply the eight per section. In Sweetie Peck, we've got eight per section in the Wolfcamp A. And then we've got 10 to 12 and – not everywhere, but in certain areas in the Wolfcamp B and Lower Spraberry. So that's the sort of level we've gone to so far. We see potential to do even more, but we're going to take it step by step. And we're bringing all our tools to bear here too. So we use reservoir simulation we use rate transient analysis to assess our completions, and then we do quite a bit of statistical analysis also. So, yeah, Sweetie Peck's further along obviously than RockStar since we just got the asset.

All right. And maybe I'll just try to slip one more in here. When we look at the 2019 guidance, you guys dropped down to 10 Permian rigs from 11 and you go to two in the Eagle Ford. What's driving that sort of dynamic there? And do you build DUCs in the Permian in 2019 while working down your Eagle Ford DUCs to achieve that Eagle Ford growth?

It's probably a little bit too granular. I'll let Herb jump in. This is Wade. But I'd point you to one of my comments about that rig count slide. It really could vary. The numbers are going to be driven more by number of wells completed obviously. And there will be, I'm confident, efficiencies gained from here to there. So it's kind of playing with the rigs and it can be a little confusing, but, Herb.

Yeah. Wade got it right on. It's basically we know when we prosecute a drilling program that we get much more efficient and the spud-to-spud timings drop from where we are earlier. So when we put the 11 rig count out there, that had certain assumptions. And we know we're already drilling faster. We just actually drilled a well, believe it or not, 7,500-foot lateral in 9.7 days. That broke all records for us. Now, we won't do to that on every well, but when you get that kind of performance, you obviously get a lot more wells per rig. And you can expect to see that over time.

Yeah. It's a shame in a way to show rig count because what really the focus ought to be on completion count because rig count is going to – I think it'll go down actually over time as we drill faster. So...

Yeah. Thank you.

Thank you. And our next question comes from the line of Jeff Robertson with Barclays. Your line is now open.

Thank you. Question on reserves. I don't know if this is for Jay or Herb. But you all, it looks like, added 44 million Boe of undeveloped reserves in the Eagle Ford at the year end and about 8 million Boe in the Wolfcamp and Spraberry. Can you just talk about – I assume the Eagle Ford reserves were added in the eastern portion that you were describing with the spacing results. And then, in the Permian, can you talk about where those came from and how much of that is Sweetie Peck versus the new asset?

Okay. Yeah, I can try and summarize that for you. So you're aware how the proved reserves work and with the SEC rules and really just doing a one-well offset to existing wells. So in the RockStar area, we obviously bought some proved reserves. And then we had a limited ability to add on because it's basically just new wells that you can add on or PDP wells that you can add on, additional proved reserves. So a limited amount there. So, yeah, most of the Permian is Sweetie Peck. In the Eagle Ford, it's the same sort of story where you're doing offsets. But we've got a lot more wells there. So we have the ability to really upgrade on performance of wells and then also add in the wells we've drilled and some of the offsets to those. So the distribution of the 2016, it's really that Pilot 7 area where we had 24 completions out of 45 completions in the total Eagle Ford. And then I showed some of where the other ones are on the east side. I don't have on the top of my head what percentage are east versus west. But you know the Pilot 7 wells were 24. That's probably about what we had on (46:11).

Yeah. I think the key message here is on the RockStar acreage that we just bought. We're not at a point yet where we can book a whole bunch of wells over a wide area based on a reasonable certainty. We're still booking on single offsets and we don't have that many wells. And now as we get forward into the future, we're going to be able to start booking these based on our own activity and other people's activity. We'll be able to book larger areas of PUDs. So you'll see PUD percentage there going up a lot. And obviously, given the production growth and the wells we'll be drilling, you should see massive reserve growth in the Permian over the next few years.

Okay. Thanks, Jay.

You bet.

Thank you. And I'm showing no further questions at this time. I would now like to turn the call back to Mr. Jay Ottoson, Chief Executive Officer, for any closing remarks.

Well, I just want to thank you all for your questions today. We look forward to sharing our progress with you through the rest of the year. Thanks again for being on the call.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day.