Good morning and welcome to the SM Energy First Quarter 2017 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to David Copeland, General Counsel. Please go ahead.

Thank you, Austin. Good morning to all joining us by telephone and online for SM Energy's first quarter 2017 earnings conference call. 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 earlier this year. We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of these 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 representatives 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 of Operations; and Jennifer Samuels, Senior Director of Investor Relations. I'll turn the call over to Jay.

Thanks David. Good morning everyone, and thank you for joining us. Just to summarize our press release and what we've been talking about this morning, we are off to a great start for 2017 and on our multi-year growth plan. Before Wade and Herb give you some details on our quarter results, I just want to highlight three major accomplishments that really are highlights for me so far this year. First, following the closing of our QStar transaction in Howard and Martin County's on December 20, we ramped our rate account in the Midland Basin up to seven rigs as of today, all of which are capable of drilling long horizontal wells for us, although one of those rig is currently engaged in coring operations. We've also been running three fracs spreads in the last few weeks. That required us to accomplish a great amount of work in a short time period in planning, permitting, contracting, facility installations and all of the other necessary operating activities in order to support that rapid expansion. That's a big deal to me. Second, we've made significant improvements in the wealth productivity we assume when we made our large Midland Basin acquisitions last year. Now Herb is going to give you more details on those results in a couple of minutes and I think they are very impressive. I just want to focus on one aspect to that which is Lateral Length. In the Martin and Howard County area, our acquisition economics assume we would average right at 8400 feet for Lateral Length during our development. We are now expecting our average lateral just in 2017 to go over 9000 peak in Length. Doing that requires a lot of land work acreage trades, agreements and doing that all while accomplishing all the other details…

Thank you, Jay. Good morning, everyone. I'm starting on Slide 4. So my summary of our first quarter results is higher production and lower CapEx, along with the closing of non-op Eagle Ford divestiture grow with 22% reduction in net debt. This morning, I have three areas to discuss with you. The first, a little more on the first quarter's results and then second, a look at the balance sheet as of the end of the first quarter, and then thirdly, a quick update with respect to our guidance for the remainder of 2017. So let's start with the first quarter results on Slide 5. Production of 12.1 million barrels of oil equivalent was well ahead of our guidance of 11.0 to 11.4. There are a few reasons for this significant reduction beat; first, in the Midland Basin. Wells, we discussed last quarter, continue to outperform and we've got 16 new wells online resulting in 55% sequential growth in Midland Basin production. Secondly, in Eagle Ford we completed a six-well pad slightly ahead of schedule and those wells came on stronger than expected. Plus we completed a few docks ahead of schedule. Herb is going to give you more color on our strong performance in the Eagle Ford later. And finally, there was also a contribution of 200,000 barrels of oil equivalent from 9 days of non-op Eagle Ford production beyond our end of February assumed close date. So while we end the quarter reflected strong well performance in shorter times to bring wells on production. Total capital spend came in at $193 million, 4% below guidance of approximately $200 million. Part of this was due to the six well pad in the Eagle Ford north coming on 8% under budget. Also with respect to other wells in general, continue…

Thanks Wade. And good morning everyone. As Wade just described, we completed a very successful quarter delivering on our production and cost targets, while at the same time significantly increasing our activity level. We are putting pieces in place for our expanded 2018 program which, as we've laid out is expected to deliver significant production growth, margin expansion and increased capital efficiencies. And we're quickly and successfully ramping up our activities. At the end of the fourth quarter, we are running four rigs and one frac spreads in the Midland Basin and Eagle Ford. Now, only four months later, we’re running eight rigs and four frac spreads in the same four place and we’re getting top quality contractors. Also importantly as of show, we are bringing out some outstanding wells in both place. Today I’m going to cover three topics. First, as Wade mentioned, I’ll give a little more color behind our production days in the first quarter. Second, we'll provide some examples of what we’re doing technically to improve our operations in the areas that really matter. And finally, we will review some new real results from the quarter which in short continue to exceed expectations in both the Midland Basin and the Eagle Ford. On the production days, we were really hitting on all corners during the first quarter. Production was above expectation at each of our field locations. The major contributors were in several categories. First, more new wells were brought on earlier than planned. This is a result of more frac stages pumped per day as a result of excellent execution on zipper fracs by our completion crews, followed by faster plug drilled out times. We are now routinely stimulating an average of 6 to 9 stages and that should add large stages per day and…

Thank you, Herb. In closing today, I just wanted to note that the priorities of the company going forward aren’t changed. Our 2017 priorities and plan focus on helping us optimize our development plans in order to maximize the value of our assets. We believe that the quality growth we’re going to generate during our multi-year plan period involve cash flow and economic drilling inventory, should result in differential performance for our shareholders. With that, we’ll be happy to take your questions.

[Operator Instructions] Our first question comes from Jeb Bachmann with Scotia Howard Weil. Please go ahead.

Good morning everyone. Jay or maybe Herb on this one for Howard County. You guys talked about doing the optimization work as well. It's a quarter log data. Just kind of trying to figure out when you think you might have that data from those programs and how we can actually implement in your next world designs?

Jeb, this is Herb. First of all, we have quite a bit of core data and we’ve got a lot of log data already. So what the additional core data is really for certain areas so that we can see additional perspective for horizon core data where we don’t have them. And also to comment on landing zones with some specific details. So I'd say it’s going to be an optimization beyond our optimizations from here but we want this really to drive up our inventory.

And I guess just looking at Slide 9, talk about the improved completion designs just wondering would you guys have any kind of recompletion opportunities that you could put that to work on at this point? Or is that something down the road that might be of use?

That really be down the road. There is not that many horizontal wells out there in Howard County and so recompletions isn’t really going to be the big driver, it’s really the new wells that we are putting out there.

And I guess just last one for me, could you guys just remind us the percent of your Permian production that's on pipe versus being trucked at this point?

I think it’s by two-third.

And the rest would be trapped.

And you guys know when it will be on pipe? Have you have any idea on that?

No, I don’t really have a number for that. That’s going to basically be rolling right because as we’re expanding the number of pads, they are trapped and then ultimately you get a hook up. So, no, I can’t really give you a number on that.

Great, appreciate the color.

The next question is from Welles Fitzpatrick from Johnson Rice. Please go ahead.

Hi, good morning. Specifically on Eagle Ford northern test, have you guys seen a difference between upper Eagle Ford and the lower Eagle Ford on those results? And as far as how they’re doing versus the curve, would you describe it as relatively similar to what you’ve seen on the east with those uplifts?

Well, this is Herb. First of all, there is six wells in that area. And when we looked at them all together combined, and we did different things in some of the wells, overall they exceeded our investment threshold by quite a margin. We ran different completion designs in the upper and the lower because the rock properties are different. So I’d say what we’re seeing right now and we believe there is some more optimization room yet, that all room exceed our inventory threshold and we got the lower Eagle Ford optimized more than the upper Eagle Ford at this point. So we’ll see continued room but it’s all making our hurdles with the way we’ve designed the completion with the 625 foot space of that well.

Okay, that’s great. And then on the cost savings on that, should we think of that 8% as taking to 5.2 down to 4.8? Or was that more cost savings on sort of some other signs that one would expect you to run on a test like this?

Yes, it was really about efficient execution. Some things where we increased the cost, some things where we dropped the cost overall but it was really basically no pick up in execution. It was by the biggest part of it. And that led to the 8% reduction.

Okay, perfect. And then just one last one more of a contextual question. It seems like the Eagle Ford is in a pretty much bunch and bound with what you guys have in the Permian now. If you guys were to accelerate, if you were to add rigs beyond what's planned, do you think that that might be a little bit more weighted towards the Eagle Ford? Or you’re kind of happy with the CapEx that you have now?

Well, this is Jay. I think if we have, and we have some interesting flexibility I think based on how things are performing with our capital program as we go forward. I think we’re going about as fast in the Permian as a prudent operator will go at this point given the data we needed collect. So at the end of another dollar you want to spend in CapEx, and obviously, as Wade would probably say, if we have another dollar spend, we will lower our debt level. But I think the Eagle Ford is a great option. The economics are very strong. It would be a very easy ad for us. And as we go through the year here, if it looks to us like it make sense from a cash flow and cash balance standpoint, I think the Eagle Ford makes a lot of sense. And maybe it will be the first place to put another dollar.

That’s super. That’s great to see those improvements. Thank you so much for the time.

Our next question is from Michael Hall with Heikkienen. Please go ahead.

Thanks, appreciate the time. I just wanted to I guess go back to the completion cadence in the quarter relative to the expectations. It was a little bit higher than what you guys have indicated last quarter. I guess how do we think about that cadence playing out through the rest of the year? Initially basically pull those out of four quarters, or is there potential that, given that you're kind of moving through completions in a faster order than expectations, it will actually see a higher completion count as we make our way through the year.

This is Herb. It’s really we are sticking to our plan basically. We’ve got flexibility now on how we do things. But because we’ve been so much more efficient in executing, we’re able to get things done faster. But we are still sticking to our plan. We haven’t changed CapEx guidance at all. So that’s really where we are.

Okay. So would there be I guess, in that context, would you potentially drop some activity, or drop a crew or something in the back end of the year? How do you kind of balance that out in your current thinking?

Well, so right now we are just executing the plan and what we've laid out, what we are going to do in the second quarter. And then, we will be looking at how to optimize it end of the year. But, at this point, we are seeing no reason to change our number completion for the CapEx field.

Okay, fair enough. And then, can you comment on what the maybe I missed this, but what the average Lateral Length was in the Permian program in the first quarter?

Well, I have it just for the first quarter because it is said that - we have been focusing on the 10,000 for laterals and they have been normally that way 9700, 10,000. So there is some, there is one pad where we did 675 laterals in that simply because least geometry to set that up. So, I will have an average, but it would be by high 8,000 I'm guessing for the quarter.

Okay, that's helpful. And then in the Permian what’s the current run rate on the full drilled completely equipped cost and how it relative to Sweetie Peck and where are those running.

Yes, I think we had that laid out in our last quarter presentation and sometime next on this one. So, you could see what how far they are at the back.

Those numbers include some - our expected cost for this year, so there is a little bit of inflation actually in those numbers.

Turn to Slide 19.

Turn to Slide 19.

Sorry, I missed that, thank you. And the last one is just, in the Eagle Ford I think there was 17 completions what was all in that 1Q '17 completion area that was highlighted I guess its Slide 13 and - 17 in that area where they?

No, that's six certainly borrow away that 1Q '17 completions are, there were quite a few over in the east area also that came on basically in mid-March. So late in the quarter.

Okay, great. Appreciate it, thank you.

Our next question is from Paul Grigel with Macquarie. Please go ahead.

Hi, good morning guys. On the uptime percentage an interesting point there, would you guys view as the repeatability of that moving forward drilling by the technology. And would have modeled into these assumptions of guidance as you look out for the rest of the year in that regard?

Okay. So, on uptime percentages we have seen progressive improvement everywhere and that's where it is systems based. And it's sustainable when we are basically in an area, if you have an offset operator flattening your way with well, that's drops time. So a very programmable if you can plan out pretty well what's going to happen for where operations are affected by other operators or your own operations. So, I would say sustainability is there from the system standpoint what we have to plan out and what you put into your guidance is really what you know in your program is effective. So, I think we have planned that out and its quite detailed. So, it's really hard to put that number out statement on that.

Okay, that's understandable. That's good color. And then maybe one for Wade. With the change in the credit agreement and the ability to up-hedging as a percent of projected production obviously in the near term you guys have ample hedging. How should we view the longer term strategy moving forward and the willingness to implement that to the greater extent?

Yes, Paul. We have added some hedges as I said and you can see that. I think what you should expect is, we will be very focused on kind of the more near term for the next couple of years especially during the periods where our leverage is highest. So, it will just be a quarter-to-quarter thing but we look at the volumes and how comfortable we are. It's actually much more than that. I wouldn’t anticipate adding a significant amount of hedges if you look out to the third, fourth and fifth year from any point in time.

Okay, great. That's makes sense. Thanks guys.

Our next question is from Bryan Levy with Key Group Holdings. Please go ahead.

Yes, thanks for taking my questions. On Slide 13 of your presentation, you heard production on a two stream basis, what does it look like on a pretty stream basis and can you quantify what sort of we could see from that?

Yes, Bryan, I appreciate the question. I don’t think we’ll tackle that one here in the call because I am not good in doing math in my head like that so if you might follow-up with Jennifer following call I appreciate that and we don’t give you VARs on well like this we terrific wells they perform really well and achieve over 150 days it’s great set of wells.

Thank you.

Our next question is from Anthony Diaz with Raymond James. Please go ahead.

Hi, good morning, thanks for taking my question. First up I was just looking to see if you could give us an update on the wiper well I know we are falling back in February and we’re expecting maybe next couple months from to get some kind of indication of what you guys answered that first I guess.

Well Antony I am not sure where you got the information we have flown back in February we recently completed well and we just started flow back we don’t have any data to share with you because it’s just way to early again I am not sure where that February think came from.

Okay, yes. My apologies then yeah and then from there that Martin County block do you guys have just Red Cross for border what kind of data do you guys have and do expect any drilling on that in 2017 I know gave Kevin just across to have paper some all are et cetera.

Yes, Herb. So we’ll be getting to that and late in the year putting a rig put there I don’t know whether we got completion that will be done after this year but it may close.

Okay, all right, that’s fair. And just my last question that 1300 acres just minus where are your focusing those swaps and those trades and kind of going forward where you guys looking specifically?

So there is really two things one is swaps one is to get to the longer laterals where we can figure the acreage to get 10,000 foot laterals fit in there and then the others to increase our working interest in those wells so that’s where we can get some trade so we’ll trade out of what we call isolated acreage it’s kind of out there in thicker places and played out to the logical operator in exchange for an operative wells looking interest in acreage and our RDC use so it’s very logical and we got three operators out there everyone is trying to do same thing and makes good business sense.

Okay, that great. Thanks guys, great quarter.

[Operator Instructions] The next question is from Biju Perincheril with Susquehanna. Please go ahead.

Thanks, good morning. In your January presentation, you showed a couple of slides with boundaries for Lower Spraberry and Wolfcamp B. And first, I was wondering if there's any update to those maps. And second, you had plans for drilling at Wolfcamp B or Lower Spraberry wells on that Southeast portion of our acreage in Howard County.

Biju, this is Herb. So first of all, no, we haven’t issued any OpEx to those now, however as you are aware with that, at this level there is a quite bit of industry activity and if you’re watching the railroad commissions reports, we feel that there is periodically new wells out there and those in some cases will be expanding what we’ve been as kind of confirmed areas within our sweet spots. And in particular you may notice those one well, well which was quite a railroad commission I believe yesterday, which looks to have move the Wolfcamp A confirmed contrast based on the IP given to that well quite a bit east. So we’re going to keep modeling those and at a logical point we’ll update those maps but we haven’t updated them so far.

And when do you plan to test either the Wolfcamp B or the Lower Spraberry on eastern side of your acreage?

It’s in our plan for late this year. So we don’t know whether we get production in this year but at least have the rig on it.

Thank you. Great quarter.

Our next question is from Chris Stevens with KeyBanc. Please go ahead.

Hi guys, good morning. Just a quick follow-up on wiper well question Let me complete one well on that area or are you going to have multiple wells tasking couple of different zones, maybe completing at the same time?

Yes, this is Herb. We just completed the one well, and as Jay mentioned we are just started to pull back on it now.

Yes, just note that number of well, Herb mentioned is only four mile, four to five miles to our west. So, I mean, clearly, you know, we've got a great, well, good looking county section out there and we are cautiously optimistic there, we just don’t have any data yet to share on the wiper, so.

Got it. And then just in terms of the optimization of the development plans in Howard County, you guys want to test the offer to spacing. So, is there any color you guys can provide on what sort of down spacing tests you guys are going to do this year?

Yes, I think you will see that we are - so far we have got quite a few what we have done tests staffed Lower Spraberry, Wolfcamp A, Wolfcamp B and you will see as we proceed through the program this year we will be doing at different stagger configurations which tighten the spacing but in the staggered manner where we've fit pay. So, you will be seeing those results coming out as we go through the year.

Okay. Got it. Thank you.

Our next question is from [indiscernible] with Stiefel. Please go ahead.

Hi, good morning guys. I apologize if you have addressed any of this, I missed the first part of the call. Was interested in the - about the core data that you collected both in Sweetie Peck and Howard County, you are wondering - if you could compared and contrast maybe the few areas and I think you’ve done at this point some spacing cash in Sweetie Peck wondering based on that data that you have seen isn't that applicable to Howard County as well?

Okay, Mike there is a quite a few things you put in there. So, first the core data we are just acquiring the core now the new core, we have considerable core from actually from the benefits of operations RockStar and QStar. So we've got that data, we got correlation with logs that’s well in hand. Now we are getting core through the full section. So, we are able to look at more prospectively and that's off rig and build inventory we hope. So, that's - the ones I just mentioned the 4400 feet RockStar and 59 feet of Sweetie Peck we don’t have that core yet, from one well at RockStar that we just finished. The spacing at Sweetie Peck - certainly everything we have learned at Sweetie Peck completion design recipes that we have been applying that at RockStar and it’s been great for us. We are - we do have staggering of wells at Sweetie Peck and that's informing us for the RockStar program. So it's part of our Sweetie Peck results have integrated tighter spacing and the staggered manner. And we really learned quite a bit on how to optimize from the past couple of years performance from Sweetie Peck.

Is it fair to say at this point you are comfortable with the spacing that you are using with Sweetie Peck and if so can you remind me what - where you settled there?

Yes, that depends on the individual horizon and how quick it is. So, you have to look at how much oil in place is in the mineral and that drives how tight is your spacing is. So, it's one of the things we went over that January call and kind of those fundamental things that really matter. So, its driven by the oil in place how tight and its really the volume that we attribute to a well, that drives what the spacing is, so it isn't so much, it’s just the spacing as you start from the 8 well per section and then you tightened it as there is more volume in price.

And I think if I remember correctly, we had 12 wells in part of Sweetie Peck in Wolfcamp A?

You think in parts of - that would be Lower Spraberry, you can do 12 and more potentially in the Lower Spraberry and in the Wolfcamp B you can do 10 or more in some cases, I don’t know what Wolfcamp A we ramped on.

I think this is Jay, I think one of the interesting differences between the western and eastern, I think here is where your frac varies are, if you heard that I guess - my impression is to make sure, that I’m right on this, in Howard County area, you probably A, B is probably kind of co-developed as opposed to Sweetie Peck where we are really kind of co-developing Lower Spraberry and the A together. And I think as you get to eastern tower base and the A, B is more of a - I’ll call it a tank in the Lower Spray and the Spray is sort of tank is close to the west side where, there is really no well frac there between the Lower Spray and the A. So there are some differences and we are learning a lot. We have those four models that we used to be able to make forward projections on these things based on the results we see and I think those will be really helpful to us on Howard County as well.

Very good. Thank you, guys.

At this time I'm showing no further questions. I would like to turn the call back to Jay Ottoson for any closing remarks.

Well thanks again for calling today and we look forward to talking to you next quarter. Thanks.