Ladies and gentlemen, thank you for standing by, and welcome to the SM Energy Company Q3 2019 Financial and Operating Results Q&A call. At this time all participants are in a listen-only mode. After the speaker's remarks there will be a question-and-answer session. [Operator Instructions] I will now hand the conference over to Jennifer Samuels, Vice President of Investor Relations. Please go ahead.

Thank you, Amy. Good morning everyone and thank you for joining us. Allow me to quickly remind you that we may discuss forward-looking statements about our plans, expectations and assumptions regarding 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. Please refer to the cautionary information about forward-looking statements in the third quarter earnings release, the IR presentation and the Risk Factors section of our Form 10-K and our Form 10-Q which was filed this morning. All of which are posted to our website. Our discussion today may include discussion of non-GAAP financial measures that we believe are useful in understanding and evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are provided in our earnings release and IR presentation. Here today to answer your questions we have President and CEO, Jay Ottoson; EVP and CFO, Wade Pursell; and COO Herb Vogel. I will now turn it to Jay for some opening remarks. Jay?

Thanks, Jennifer. Good morning, everyone. I hope you've all recuperated from eating all those sugary treats. I just wanted to take a minute ahead of Q&A here just to emphasize our recent progress on cost reduction, because I think we've under-solved to some extent a noteworthy achievement. During the third quarter, our operations team along with our terrific vendor group drilled and completed wells, much faster than our expectations in our plan. For example, we pumped more than nine stages per day per spread on average in the Midland Basin, a 23% improvement from our expectations, and that directly translated into quantifiable capital efficiency as our well costs are now averaging right at $700 per lateral foot. Now that number is clearly top tier. I know one of our larger peers announced Midland Basin well cost of around $790 to put to some acclaim, late earlier this week. Our improving capital efficiency will obviously directly translate into lower 2020 capital costs and supports our commitment to generating free cash flow. We've already achieved a nearly 10% improvement per lateral foot over our 2019 plan cost and we're still working. Combined with lower operating costs and actions we've been taking to reduce G&A we're positioned -- we think for a very positive 2020. And I hope the higher third quarter CapEx didn't spook you because it's just the evidence of our faster drilling and completions pace, while we reported 19 net flowing completions in the Permian, we actually completed a number of additional wells that will come on during the fourth quarter, we just held up production to better manage our pull back costs. So in short, we're extremely pleased with our capital efficiency and its implications for our 2020 performance. So, operator, let's turn it over for questions.

[Operator Instructions] Your first question today comes from the line of Brad Heffern of RBC. Your line is open.

Hey, good morning everyone. I'll start with a question on the Chalk. So, you guys obviously have the four wells now, they're sort of spread out across the acreage position. Do you have a feel now for how consistent that play is going to be, and any clues as to what the inventory might look like?

Brad, this is Herb, so yeah we're real pleased with the Austin Chalk results, both rates and the liquids content are great and the returns are great. What we liked about it is the consistency that it does show in terms of the rock across the acreage. And then we can predict the variability in a liquid. We'll be doing an inventory assessment as usual at the end of the year and we would be publishing that in February like normal. So, but yeah, we're pleased with what we're seeing so far.

Okay. And then you guys mentioned that you dropped the second Permian completion crew, is the plan for that to stay down for all of the fourth quarter and then for it to come back at the beginning of next year?

Brad, this is, Herb. So we were running three frac spreads in the third quarter and we dropped to two just at the very beginning of October. And we're just going to continue that until we get our budget lined out and we'll figure out the level, will be doing next year, at that time.

Okay. Yeah, thanks for the correction, I'm sorry. And then I guess you know with the prior quarter release, you guys talked about shut-in volumes in the second half of around 8,000 barrels a day, I was just curious if that's approximately what the 3Q number was? And if you have any estimate of what the 4Q number is. I'll leave it at that. Thanks.

Yeah, we don't really put out an estimate on our post the result. It's a difficult thing to estimate, but we know, we have shut-ins and they're hard to forecast, because there is a lot of operators offsetting as you probably have seen how much offset operating activities out there, because Power County is quite popular right now. So we do have an embedded assumption on in terms of shut-ins and that's true for the fourth quarter also.

And I would just add that it was consistent with our expectations in the third quarter.

Yes.

As baked in the guidance.

Okay. Thank you.

Your next question today comes from the line of Gabe Daoud of Cowen. Your line is open.

Hey, good morning everyone. Obviously, some nice and improved results out of the Eagle Ford, but I guess on our numbers we still kind of show the Permian is being more accretive to returns and free cash flow, and also just from a de-leveraging standpoint. So, I was curious, Jay, if you could maybe just talk about how you're thinking about capital allocation between the two plays in 2020?

Again, this is Herb. So obviously we see value in South Texas wells, and we've really proven that with these latest wells and I know people have been waiting for those for a while. But we see a clear path to additional cost savings and productivity improvements and that we anticipate enhancing returns where the wells will be competitive in the portfolio and that will be even more so, once those midstream contracts expire or have lower rates as we've talked about before. So as we've said we'll plan to spend less in 2020 than we did in '19, and it will really be to confirm these better returns. And right now, we're basically in the budget process and we'll share that in February, what the ultimate capital allocation will be.

Thanks for that. That's helpful. And then just a follow-up I guess obviously doing a great job on D&C per foot in the Midland, just kind of curious you're closer to 10% target. How do you think that shakes out I guess that ultimately hitting the 10% and if you think you could even exceed that at this point? Thank you.

Yeah. Gabe again this is Herb. So yeah, we do see the potential to reduce costs further. Obviously, we're in a deflationary environment, and then we are seeing a different ways that we can get the same productivity with slightly different completion design that helps flatten the cost. So, yeah, we see the potential for lower.

Your next question comes from the line of Neal Dingmann of SunTrust. Your line is open.

Good morning all. Jay, my question, you guys continue to have, you said the efficiencies is well noted by your cost. I'm just wondering, when you look at the plan for next year in order to achieve -- continue to achieve these higher efficiencies. How do you think about as far as the number of sort of rigs and spreads needed to be run versus obviously the test of trying to stay closer to cash flow, because you're getting a lot of times, there is always the argument of having to run the high -- that the -- the higher activity to stay more efficient, but I'm just wondering how you all sort of view that.

Yeah, Neal this is Herb. So we put together a program with activity for the year, and then as activity as we're faster and executing were more efficient. We have a choice of dropping rigs or dropping frac spreads or doing more activity, and we basically look at the free cash flow level on the commodity prices and make that call. So that's just what we've done now as we said, we're going to stick with the capital, we said we would for the year, even though we've been much more efficient and that led to going from three to two frac spreads in October. And we'll get all our activity and more for the same capital.

Got it. Makes sense. And then just to follow up on that. The efficiencies that you're seeing, I mean is it largely through just the longer laterals? Is it continuing to improve the completion design? And I'm just wondering anything else you can sort of shed on that how you continue to achieve such great prices there?

Yeah, I would say it's all the above, but the number one one is the consistency of using the same frac providers and the team we have and looking at every minute of execution and optimizing there. So it's really comes down to people that are out there doing the work.

Great. Okay. Thank you.

Your next question comes from the line of Leo Mariani of KeyBanc. Your line is open.

Yeah, thanks. So just a philosophical question, I know you guys have mentioned it a number of times, I know the budget is not set for next year. But you kind of continued to mention about kind of planning for neutrality. So just to be clear on that. So essentially is the plan to as the end of the year approaches and early next year we sort of get there. And obviously you guys have hedges in place. As you look at the budget, are you truly trying to set that at a neutral level and then whatever activity sort of falls out from that -- sort of, so be it. Is that kind of the philosophy?

No, this is Jay, and our philosophy is working to generate free cash flow. I mean that's what this is about. We want to have a positive free cash flow yield. We're doing everything we can, pull on every knot we can, working on every angle we can, to get ourselves to that point.

Okay. Obviously you've documented a lot of the well cost reductions, which clearly will benefit you folks. Are there any other sort of major things, I know you guys have talked about G&A, anything else that you can kind of do to kind of get that spending down?

Well, we lowered our LOE -- LOE guidance as well this quarter. So in general, all our costs are moving lower and certainly we're working on every single line item of cost and every single thing we can to make the wells better sourced. We're going to -- we're going to do everything we can to get to a positive free cash flow yield. We think we can do that in 2020.

Okay. And then I guess just on the Eagle Ford, you all talked about some plans to kind of lower the well cost there, obviously well documented 10% reduction in the Midland. As you sort of further that plan down the road, I guess do you expect to see a similar type of reduction in the Eagle Ford, maybe 12 months from now, we can get kind of 12% off those costs there, what we sort of sit there?

Okay. Leo, this is Herb. So you probably seen in previous earnings reports, we've talked about $650 per foot in the Eagle Ford, and we expect the same sort of environment there which would be deflation in addition to completion enhancements, and we have specifically identified where those could be, and we would implement those next year.

Your next question comes from the line of Karl Blunden of Goldman Sachs. Your line is open.

Hi, good morning, thanks for the time. We're not there yet, and I think your maturity schedule allows some flexibility -- like flexibility versus some peers. But as you think about cash flow of 2020 if it's not forthcoming for 2020 and 2021 as you're planning. What pods do you have for the '21 and '22 maturities? In what ways could you refine or extend those?

Yeah. This is Wade. I think you said it up well, and we do have some -- we have several years here to deal with this. The first real maturity is not till the end of '22. So that -- I guess I would say, given our liquidity situation, given the time between now and then, given the plans for getting within free cash flow, I definitely see chipping away at that between now and then. And again, lots of liquidity in the revolver as well, to use some of that if needed. But there is just a lot of things that can change over a two or three year period as well. So I feel like we have a lot of flexibility and we're in a good place to deal with those as we go from here to there, and will between now and then we'll watch the capital markets do, those could change. But lots of flexibility, I think we have more time in most of our peers as you said, to deal with these.

Makes sense. I guess just to be a bit more specific on the ways in which you can be flexible, would you still see convertibles as an option, you know the market cap is down from when those the existing ones are issued and their non-core assets as well. Basically just trying to assess the reliance on the capital markets?

Yeah, I know you mentioned a couple of other things, I mean, there are many options and I would not say that we would take a look harder at one versus the other, right now. I mean things are -- things change a lot and there are a lot of options out there. So that's all I'll say on that.

Great. Thanks and congrats on the good progress.

Yeah. Thank you.

Your next question comes from the line of Joe Allman of Baird. Your line is open.

Thank you and thanks for all the comments that we're seeing today. So my first question is in terms of your 2020 targeted debt reduction, do you expect to reduce debt on an absolute basis and reduce the leverage ratio solely through free cash flow? Or do you expect to also add some other means such as asset sales? And if you are thinking about asset sales, what particular assets are you thinking about?

Well, I'll take the first part we are, as Jay said, very clearly, we are planning to generate free cash flow next year. The use of that free cash flow would be debt reduction. The leverage metric also will be going down toward the lower [indiscernible] area, so combination of those two and there are other possibilities, I guess I'll let Jay, talk about that.

Well, certainly asset sales were always a possibility. It's not a particularly constructive market for asset sales right now. We'll look at, we look at all the alternatives and we'll make the best choice we can on behalf of shareholders at the time.

Great. Thanks for that. And then I know in July you said that in 2020, you expect to spend about the same amount as in 2019. And I think yesterday, you said that you expect 2020 to have a similar-sized operations plan. So with your improving capital efficiencies and lower costs, does that mean for 2020 a similar spend or does it actually mean less spend, but a similar amount of activity?

Well, I don't think we actually said yesterday what our program would be for 2020. What we said is at a similar level of activity, we would expect cost to be lower. In a general sense, I think we have talked for quite some time about 2020 activity being relatively flat to 2019. Again, we won't guide that until February. At that same level of activity, we would expect cost to be lower. So in a general sense, I would say right now, we are assuming that our capital program will be smaller than it was last year in terms of dollar spent or should say lack this year. 2019, still this year.

Your next question comes from the line of Kevin MacCurdy of Heikkinen Energy. Your line is open.

Hey, good morning. I was hoping maybe you could provide a goalpost for 2020 South Texas activity. Compared to the '19 wells this year, we kind of talking about double-digit completions or maybe just a handful. I'm just trying to get an idea of how much you'd be willing to cut to get the free cash flow next year?

Well, that's really two different questions. First, in terms of goalpost for activity, I think we've already said we're still looking at our budget, we're not going to guide that. Our activity will be lower. Our net spend in South Texas we expect to be lower than it was this year. And we'll -- as we are getting toward that time there, in February we guide, we'll tie that up. We're going to do as we said earlier, we are very committed to the objective of achieving free cash flow next year. We're really excited about the progress we've made at these Eagle Ford wells, but no, free cash flow is our primary objective, so we're going to do what we need to do.

Okay, and that's helpful. And on the opex side you made great progress on LOE, this 4Q a good run rate for 2020 or what could you do to get that even lower?

So, Kevin, obviously, we haven't done our budgeting activity, but where deflationary environment and we are trying everything we can to drive LOE down. And I would expect that to continue, but I don't have a number for 2020 at this point.

I would only add there, that you know as South Texas becomes a smaller proportion of total LOE. But that kind of counter some of the additional savings will generate on the Permian side. Because it has such low LOE. And obviously, we're talking about less spending in South Texas next year.

Your next question comes from the line of Oliver Huang of Tudor Pickering Holt & Co. Your line is open.

Good morning, and thanks for taking my question. On the Eagle Ford, the results from the new JV design certainly look encouraging. I was hoping that you all might be able to elaborate on the details as to what you've learned from the spacing tests? And if there are any specific reasons as to why no Upper Eagle Ford wells were targeted utilizing the new JV design?

Oliver, this is, Herb. What we are really striving for was to get higher returns through longer laterals and the wider spacing. And so that's why we were really proving with that program. And we want to see the results and you can see where they are. From here we know what we can do to optimize and we're going to continue to do that because as we've been stating we're trying to get higher returns and that lead to free cash flow earlier.

Okay, that's helpful. And I know it's still very early days on these wells, but what might this imply in terms of wells per section that you all are willing to underwrite in that northern Eagle Ford area, just based on the data that you all have today?

So Oliver, we do that resource assessment at year-end and we're going to -- going to go over all our inventory that would be in February. So we'll take what we've learned this year, we'll lay it out for next year and beyond. And that's when we do that exercise, so I wouldn't venture a guess at this point.

Your next question comes from the line of Betty Jiang of Credit Suisse. Your line is open.

Thank you. Good morning. On outside impact, just wondering how much of this impact is being caused by third-party operators versus your own activity? And would you be able to manage the schedule around to avoid or reduce this issue over the next several quarters?

Betty, this is Herb. I'm assuming you're talking about the Permian. And there is a combination of our own activity as well as offset operators. We can control our own activity and we understand what we need to do there and offset operator activity, we're all in communication with each other to make sure we don't harm each other's wells. But it's very variable and depends on which wells you're talking about and what the location is. So it's not something that is easy to forecast.

Got it. But in terms of the impact is that -- should that improve in the coming quarters? Since we're going into the second quarter of seeing that tempering your production in the Permian?

Betty, as I said, it's really hard to forecast, because it depends on what an offset operator will do and where they lay out their program, and we don't have their program for 2020. So we can't say which quarter they'll be active, at what point they'll be drilling and at what point they'll be completing wells. We can do that for our own, but as you can see we have quite a large perimeter area where there are offset operators.

Okay.

So that continuing -- continuing piece that we have to include in our guidance and we keep doing that and we've been fairly accurate with what we said today.

Got it. Okay, thanks. And then my follow-up, there is many questions on the free cash flow for 2020. Eagle Ford activity is certainly on obvious lever to the capex budget. But what tempering Permian activity be an option to that balance as well?

Well, Betty, it all comes down to returns. And I think clearly where we're looking to prioritize free cash flow, because we want to prioritize absolute debt reduction. So we're still working a number of different alternatives, looking at various growth rates, how much free cash flow they generate versus how much cash flow growth debt adjusted per share type growth they generate. We haven't gotten to the point yet where we can't exactly say where we're going to land. In general, we -- moving more toward the direction of free cash flow and debt reduction. But we'll give you official guidance on that, after the first year.

And let me just add one thing on that piece and that's, we want to be able to optimize our Eagle Ford and Austin Chalk developments in the future. So we want to run that at a pace that enables us to optimize or not sub-optimize by drilling a fast program. So we want to do that at the right pace and that's how we're going to decide the program.

Got it. Could you remind us what's your budgeting on commodity price assumptions, whether it's strip using strip or something a bit more conservative?

We'll run strip. We'll run the strip case. And then we, as you know, we're very well hedged for next year, but we generally run strip cases for our budgets.

Okay, great. Thank you.

Your next question comes from the line of Biju Perincheril of Susquehanna. Your line is open.

Hi, good morning. Kind of early in the Austin Chalk program, but at this point, any early read on sort of relative economics of the Austin Chalk wells versus the new Eagle Ford completions. Anything you can say about mix going forward?

Biju, this is Herb, so we have a lot of room to optimize the Austin Chalk. Since really we have four fully dedicated wells to date and we're pumping Eagle Ford completion, so we will be potentially modifying that, as we learn more for the Austin Chalk. In terms of mix, we have not lined out that mix for 2020 yet.

Okay. And then maybe in the Permian, what kind of care would you need to keep production flat with where it is today or in the third quarter?

Biju, that we've been saying somewhere in the 80 to 85 range, but it could be a little bit less depending on where the wells are, but that's the sort of number of completions, you need in a year.

I think it's pretty clear, if you look at our third quarter results and our base has been outperforming our expectations. We actually beat in the third quarter with fewer completions than we -- fewer flowing completions than we anticipated. So the basis is actually doing a little better than we expected.

Got it. And that is from downtime management, I mean, is that what is driving that and is there more room to -- I bet for better days products in management.

Biju, I would say that the combination of us, in conservative in our base production forecast and actually getting better uptime than planned, and better well performance overall. So there is a number of contributors to that, and it's impossible to pin down exactly which one it is.

Your next question comes from the line of Mike Scialla of Stifel. Your line is open.

Hey, good morning everybody. The reorganization that you're implementing, wanted to see if that is going to limit your ability to grow in the future or does it give us an indication of your outlook that you're kind of preparing the company for a lower growth area in oil and gas?

Yeah, Mike, that's a great question. I think are -- really what we're looking at -- we're just looking at our activity operates mostly in operating reorganization in the sense that we've always run as a regionally focused company. And when you look at our planned operations now for the next few years, we're going to be largely Permian based. And as you start to look at there is redundancies obviously in management positions and other things by having a regionally focused organization. So it just makes sense to us, to simplify our operations and eliminate some of those redundancies right now. We're going to continue to have a robust exploration effort here, continued robust looking at new opportunities, business development. We're not cutting those functions. Really, this is just an opportunity to streamline -- the operations portion of our business. So I look at it, I don't see this is an impediment to growth at all. I think it's a normal streamlining that you would do, given the situation we see going forward. I'll also note that, and it's important to people know, we cut our head count here by a third over the last four years. And so you look at this cut, and say, well it's not that big a cut and it is -- it's additional on top of the third, we've already reduced. So we've been very attentive to G&A and very focused on our efficiency. But I don't think we're given our future growth here in what we're doing.

Yeah. And I'll add on that one that, we're really view ourselves as one of the most technically proficient operators and we've been very careful to ensure that we maintain our ability to be at the cutting edge from a technological standpoint. And we've really preserve that with the way we've reorganized.

Got it. Some good insight. And I guess, obviously, you haven't formalized the 2020 plan, you've got lot of questions around 2020, just wanted, given that it's 80 to 85 [indiscernible] to keep things flat. I assume you're still planning on base case at this point, based on what you know that you still generate some growth next year?

Right, I think I addressed this earlier, we're running a range of alternatives from very low growth to some growth and really focusing on how much free cash flow and how much debt adjusted per share cash flow growth we get, because we want to reduce absolute debt, and we also want to reduce leverage. And those are the knobs we're turning. And obviously we need to achieve very high capital efficiencies to do well on those metrics. Other than that, we'll just have to lead that until we actually guide.

Understood. Last one is just...

Yeah, Mike, I guess one point is, I mean oil production is going to grow, right? Permian, we're going to grow in the Permian, there is no issue with that. Okay. But how much -- and how much -- what happens in the Eagle Ford, in terms of gas volumes, we'll see how that works out.

That's helpful. Anything you can share at all on your discussions with EnCap at this point?

EnCap?

Yeah. I assume you're asking because of the filing yesterday. I mean at -- I don't think we have any color to add to that. I mean it's, we probably shouldn't speak for them. We did notice that they did the same borrowing on a number of other holdings though, that probably all we should say.

Well, they've held our stock for a number of years as a result, we gave them stock during an acquisition, as you're aware.

Your next question comes from the line of Gail Nicholson of Stephens. Your line is open.

Good morning. I know you guys have been working to optimize artificial lift in that piece of the improvement in the LOE. I was just wondering if you could talk about what that optimization entail and does that change, I mean, at the flowback of the wells?

Gail, yeah, there is a lot of pieces to the answer to that one. But first of all on an LOE side, when we are able to switch from using generators powered by diesel for power rather than electric line power, that is an LOE reduction. So that's one aspect. When we're able to switch from ESPs to gas lift that's another reduction in LOE. And then -- when we initially turn on wells if we're using high pressure gas lift versus ESPs electric submersible pumps, that will change the character in the first 30 to 60 days somewhat. But in terms of recovery over year it's not really going to be very different. So you'll see some little differences that the first 30 to 60 days, but after that it's pretty similar. But we are focused on the LOE side also.

Okay, great. And then, I mean, everyone is talking about the Eagle Ford, which is great, this quarter. But I asked about the Midland was very impressive as the 11 new wells that you guys disclosed on Page 6 are tracking with the previous average. But the bulk of those wells were Lower Spraberry are on the eastern, add to the asset which typically has a lower IP [indiscernible] clients. I was just curious if those Lower Spraberry and our eastern edge execution was actually outperforming expectations or if you did anything different in the design there?

Again, yeah, that is a great point. There are some wells actually on the eastern edge that were performing extremely well. And Lower Sprayberry is were mixed. But wherever there is a lower IP we tend to see the lower decline rates, so that will offset each other. So you can have a great well, initially, which has a great IP and then a more rapid decline in the Wolfcamp A and then it's offset over time by a lower Spraberry as that have the opposite behavior. Now we're real pleased with the results there.

And thank you for noticing that we spent a lot of time talking about something that's a relatively small percentage of the program.

And at this time there are no further questions in queue. I turn the call back to Jennifer Samuels.

Well, thank you all for joining us today and I look forward to seeing a number of you, I believe at the upcoming conferences this month. Thanks.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.