Jay Ottoson - President, Chief Executive Officer Wade Pursell - Executive Vice President, Chief Financial Officer Herb Vogel - Executive Vice President, Operations Jennifer Samuels - Vice President, Investor Relations

Good morning. My name is Judy and I will be your conference operator today. At this time I would like to welcome everyone to the SM Energy 2018 results and 2019 Operating Plan Q&A Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks there will be a question-and-answer session. [Operator Instructions]. Thank you. Jennifer Samuels, Vice President, Investor Relations, you may begin your conference.

Thank you, Judy. Good morning everyone and thank you for joining us. As usual 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 the website for this call and the risk factor 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 directly most comparable GAAP measure and other information about these non-GAAP metrics are described in our press release for this call. Here today with me to answer your questions are Jay Ottoson, President and Chief Executive Officer; Wade Pursell, Executive Vice President and Chief Financial Officer; Herb Vogel, executive Vice President, Operations. And with that, I’ll turn it back to the operator to open it up for questions.

[Operator Instructions]. Your first question comes from the line of a Michael Scialla of Stifel. Please go ahead. Your line is open.

Good Mormon everybody.

Hi Mike.

Morning.

You mentioned in both the prepared remarks and the release that one of the goals here is to reach free cash flow in the second half of ‘19 and to sustainable free cash flow and growth beyond that. Just wondering how you are looking at, did you cut spending for 2019 versus ’18? What are you thinking beyond ‘19 in terms of what kind of spending it would take to sustain that growth in free cash flow and maybe what kind of growth are you looking for?

Mike, its Wade. From a CapEx standpoint, it’s a similar level in the out years and I think I mentioned growth being like high single digit percentage annual growth is the goal and then again continue to generate free cash flow.

Okay and looking at 2019 specifically, it looks like the first quarter CapEx is higher than the rest of the year. Just wondering, I know you are adding a sixth rig. But I’m looking at your slide 29 and it looks like completions are actually lower in the first quarter. Just wondering what’s driving the bump in the CapEx there?

Yeah Mike, this is Herb. So it’s really is a way to look at, it’s really the first half is about 60% of our CapEx, and the second half is about 40% which is about the same as last year. So it’s you know – quarter-to-quarter it just depends on how many completions we actually put in the ground in the first quarter in the pace and if you look at last year our pace was more rapid than we had budgeted. This year hopefully you know we've increased the pace in the budge quite a bit. We’ll see where we actually come in on that one. But the split quarter-over-quarter, it’s really I’d look at it as first half 60%, second half 40%.

Okay. And then last one from me, I just want to ask about the Chalk. Looks like it’s a pretty interesting well that you have there. How are you thinking about that? I know it’s been viewed as traditionally more of kind a conventional or a play that relies on sweet sports, at least relative to the Eagle Ford. Any thoughts? I know you discussed the results on one well so far, but maybe what drove you to that particular location and how widespread do you think the play could be?

Right. On the Austin Chalk actually we are pretty happy with what we’ve seen and we actually have more data than just that one well. We have partial penetrations and I think I showed three of those on the map, and then we have one that’s almost entirely in the Chalk for the Northwest and then this was our first really where we dedicate and got a lot of data and we were really happy to see you know yields of 2x to 6x, the lower and upper Eagle Ford and the NGL yields of 20% to 30% higher. So what we're really looking at is how do we integrate our development between lower, upper and Austin Chalk going forward and we have it mapped pretty well. We have a lot of penetrations in the Chalk. So the way we are looking at is having quite a bit of upside, but we're not going to account at all in there yet, because we want to get more well and this next well which will be a longer lateral, we want to see how that does. So that's really the color on the Austin Chalk.

Great, thanks for that.

Your next question comes from a line of Oliver Huang of Tudor Pickering. Please go ahead, your line is open.

Good morning, everybody.

Hi Oliver.

Last I checked, references 12 to 16 years of economic drilling inventory at current activity and cost levels in the Permian with 50% of your acreage perspective for four to five zones and two to three in the other half. Could you all walk us through that comment from an aerial perspective and also if there is any sort of risking factored into your location account?

Okay, Oliver this is Herb. So let me go over that, so you know the number overall is real similar to what we showed last year, where its just you know one year less of completion. But we look at the traditional three Lower Spraberry, Wolfcamp A and Wolfcamp B. Then there’s been considerable offset activity in the Middle Spraberry and Wolfcamp D, primarily on the Westside. So there is also Dean. So when we say five, its generally the three plus middle Spraberry and Wolfcamp D and some of the areas mainly on the Westside, and then you move east and you go to areas where there is two to three and that’s really the basis for those areal distributions that we’ve got there. And then the risking side, side B’s are sowing basically certain spacing levels which we don’t risk because of how much well control we have around us. If you looked at how much drilling has been done in Howard County in 2017, 2018, it’s really quite well de-risked. There is a little, you know we obviously have wider spacing in the intervals that have less data like the Middle Spraberry and Wolfcamp D. Did that help out Oliver?

Yes, that’s perfect. And for my follow-up, was just wondering if you all have a blended ROR for your remaining inventory, at call it 55 WTI and 275 Henry Hub or whatever that you have readily available in the Permian and also with that number might be in the Eagle Ford?

Yes, so we really do it like that for the program overall. For 2019 our returns are over 40% on that price deck.

And the Permian will be slightly higher than the Eagle Ford, but that’s really the outlook.

And does the longer term inventory that you all have, has that changed drastically from what you all are drilling in 2019?

No, I mean the mix will change. You know we don't have much in ‘19 in the way of Middle Spraberry or Wolfcamp D or Dean, but we’ll have more of that later as time goes on. Our returns wise, you know the methodology, we are totally returns focused and you know we are only designing DSUs with that last well and the spacing decision there is 25% return or better and that's really what we're focused on. So you'll see our spacing a little bit wider than some of the peers, because we don't go to that and NPV10 type of methodology. We really want that 25% return on the last well drilled.

Okay, perfect. Thank you very much.

[Operator Instructions] Your next question comes from the line of Paul Grigel of Macquarie. Please go ahead, your line is open.

Hi, maybe following up first on kind of into 2020. On 29 you guys show DUC’s building into your end with the lower Eagle Ford count. Should we view that as a bit of a tailwind into 2020 to helping that spending level or is that just a timing related issue on pads?

Yeah, I mean I remember the DUC count from year end ‘18 going into year-end ’19; it's just slightly lower. It's actually quite similar, so it’s just timing.

Okay, and then you guys mentioned 43% to 44% oil mix throughout the year. How should we be thinking about that given more the focuses in the higher oil cut of Howard County throughout the year versus kind of increasing throughout the year, maybe the cadence there?

Yeah, it’s pretty straightforward. You know we lose a little bit of oil from the condensate in the Eagle Ford where it drops about 200,000 barrels from ‘18 to ‘19 and that's just because of where we are drilling in the Eagle Ford. So that's one component of the change. The other is the Permian program overall. It goes from 79% oil in 2018 to 78% oil in ‘19 and all that is, is just a little bit of where we're drilling, but primarily it's just a normal slight GOR increase that you get as time goes on with the well, so that's really the story there.

Okay, and then lastly you guys make a reference to the PDP decline rate of the Permian program. Do you happen to have the Eagle Ford program PDT decline handy?

It’s in there also, so you'll see it at the side. I think its 29% the first year and the second year, I've got – I put it on the remarks yesterday.

Okay, thanks so much.

Your next question comes from the line of Michael McAllister of MUFG. Please go ahead, your line is open.

Good morning everyone. With the program set up the way it is and going into 2020 and keeping things the way you kind of are leaning, where free cash flow should be hopefully more beneficial or higher, is it time to harvest the free cash flow and to pay down debt or is it time to just grow the EBITDA so that the metric looks better?

Yeah, no that’s a good question. From a use of free cash flow standpoint, I think in the near term you'll see us reduce debt. Our goal is to get leverage down into the, you know into the 2x area, so that's a pretty important goal for us, so you'll see us using the free cash flow to get down to that level first.

But on an absolute basis, not just increasing the denominator?

No, it would be both. Yeah, I’d be reducing absolute debt.

Okay, okay.

And growing cash flow at the same time, so obvious you’ll see a…

Yeah, a combination, but I just want to know then the absolute level. So, you know let's say we get in an environment where the oil price goes up higher and you are as efficient as you were in 2018, would – you know you could accelerate that by increasing CapEx and increasing activity to get the 2020, hopefully get to a bigger base. How do you balance that with you know the idea that you – I guess what I'm asking is, is the Permian at a point where it can be harvesting or do you have to grow it to a little bit of a bigger size and want to get it to that?

I think absolute debt reduction would be the goal first, and you know versus the temptation of exhilarating and then out spending a little bit more. We want to maintain the levels of outstanding that we’re forecasting right now and get absolute debt reduction lower. So we're going to use whatever free cash flow and if it's more because of a higher commodity price, then that would be great.

Alright, great. Thank you very much.

Your next question comes from the line of Stark Remeny of RBC. Please go ahead, your line is open.

Hey guys, thanks for taking my questions. I was just hoping you might be able to provide some clarity around your natural gas processing force measure in the Permian. When do you expect a final resolution and do you have any commentary on when you are – or what the level of impact is factored into the first quarter guide?

Yes Stark, this is Herb. So the force measure we mentioned in the fourth quarter, they were two different plants. One of those plants is back online. The other plant, we've been told by the management of that company that they expect to have that plant back online by the end of February and usually you know there's some flexibility around that. Sometimes it can take a little bit longer, but just through the middle of February we basically see about a $200,000 fairly equivalent impact from that plant following that shut-in and then if they come online then obviously our – we've modeled no more shut-ins from that plant after the end of February.

Okay, perfect. And then I guess just on the Eagle Ford, can you give any color on what you've seen on JV activity and then how should we think about activity beyond say 2019?

Okay, so let me go first on the JV. So you know initially we did quite a bit of data gathering and we're real pleased we did our first Permian fiber optic installation. We got a lot of data that really helped us optimize the completion design. Together with the JV partner, we also started putting the wider spaced wells in. So as we get into the middle of 2019 we expect to see results from those wider spaced wells and that extends on into late 2019 with more wells. So we view it as quite beneficial. We're looking at it, the data, there’s a lot of data analytics going into that. Looking forward we’ll see where things go and whether we do more JV activity or not. When we see a lot of value and we can ascribe that, then we would consider doing more, but right now we don't have that factored in, other than the straight JV we've gotten in 2019 that we know the terms of.

Okay, thank you very much.

Your next question comes from the line of Michael Scialla of Stifel. Please go ahead you’re your line is open.

Yeah, just maybe to follow up on the Eagle Ford. Outside of the JV it looks like you're doing some drilling this year. You mentioned the Chalk already, but are those other wells primarily Galvan Ranch or are you going to be drilling some SM only well in there.

So, are you saying drilling or completing?

Well, both.

Oh, okay. Well there’s a little bit of a difference there, but yeah, there I’d say for our 100% well there is more Galvan Ranch than Briscoe Ranch. The more of the Eagle Ford East than the Eagle Ford North, although there are some Eagle Ford North wells.

And are those Eagle Ford North wells primarily to same acreage or you feel like you've learned enough from the JV now that that area competes.

No, these are definitely for returns and they are high liquid content wells. So these are not about acreage saving that we have consolidation agreements out there which allows us to drive for better returns.

Okay, and you mentioned on your spacing set, 770 feet in the Midland within zone. I think you previously talked about testing as tight as 420. Is that an apples-to-apples comparison, and if so what drove the increase in spacing there.

So for our 2019 program the range is 420, so we have some 420’s within zone and all the way up to 1320 within zone and so the 770 is just an average of the entire program and you know there's a number of areas where we’re holding acreage and we're spacing wells at 660 to 880 where we do two well pads to hold as much acreage as possible and those are average in there. So just when you look at the entire program, that 770 and that's within zone, they can actually be – you know in some cases you can almost you know not quite stack, but stacked over each other, so we’re not counting it that way, we're counting it just within the zone. That makes sense?

Okay. Yeah, so I guess the 770 is not necessarily what you anticipate to be your final development spacing…

Absolutely not, no. No, it's very much we customize it by area and interval and you know we have so much data now that we can really hone in on that fundamental conclusion of getting those returns that are greater than 25% for that last well drilled. So it's really the returns side that we're focused on.

Okay, and that 420 still looked like a good estimate at least for the western acreage at this point?

Depending on where it is and one of two intervals. Yeah, that looks like it can work and we're obviously getting more and more data and we'll decide, okay, is that going to be a 25% return or do we want to go a higher return, that's the sort of evaluation that we’ll do.

Okay, and then just to add one more. On your approved reserves you have some nice addition, but you also had revisions of 69 million boe. Was that price related or any performance related revisions in there?

So you know that, the lion's share of the revisions originates from that redesign of the development plan in the Eagle Ford. So when we widen the spacing and our revised development plan, we eliminate some PUD locations and we deem that PUD removal of a revision, and that's kind of what you got in those 69 barrels. Also in some cases with the higher returns from those wider space wells, we’ll actually move some of the existing PUDs out of the five year horizon, so then we call that – it’s because of the five year rule revisions, and that’s in those 69 million barrels. So it's – most of the revision is in the Eagle Ford and some related to the development plan. Now there's some smaller ones in the Permian, but the key thing is really development plan in the Eagle Ford.

Very good. Thanks Herb.

Okay.

And there are no further questions in the queue at this time. I turn the call back over to Jay Ottoson, President and Chief Executive Officer.

Well, I just want to thank you again for your interest in our company and I look forward to talking to you when we have our first quarter results. Thanks again.

This concludes today’s conference call. You may now disconnect.