SM Energy Co (SM) 2019 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the SM Energy Company Q3 2019 Financial and Operating Results Q&A Call.

(Operator Instructions) Please be advised that today's conference is being recorded.

(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?

Well, thanks, Jennifer.

Good morning, everyone.

I hope you've all recuperated from eating all the sugary treats.

I just wanted to take a minute ahead of the Q&A here just to emphasize our recent progress on cost reduction because I think we've undersold, 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 and our plan.

For example, we pumped more than 9 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, and that number is clearly top tier.

I know one of our larger peers announced Midland Basin well costs of around $790 a foot to some acclaim late -- earlier this week.

Our improving capital efficiency will obviously directly translate into lower 2020 capital cost and supports our commitment to generating free cash flow.

We've already achieved a nearly 10% improvement per lateral foot over our 2019 planned costs, 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.

Now I hope that a 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 flowback 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.

I'll start with a question on the Chalk.

So you guys obviously have the 4 wells now.

They are 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 yes, we're real pleased with the Austin Chalk results.

Both the rates and the liquids content are great, and the returns there are great.

What we like 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 the liquids.

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 yes, 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 3 frac spreads in third quarter, and we dropped to 2 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 we'll be doing next year at that time.

Okay.

Yes.

Thanks for the correction.

I'm sorry.

And then, I guess, 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?

And I'll leave it at that.

Yes.

We don't really put out an estimate on outpost the result.

It's a difficult thing to estimate.

But we know we have shut-ins, and they're hard to forecast because there's a lot of operators offsetting us.

You probably have seen how much offset operating activity is out there because Howard County is quite popular right now.

So we do have an embedded assumption on term -- 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.

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

Obviously, some nice and improved results out of the Eagle Ford.

But I guess, on our numbers, we still kind of show the Permian as being more accretive to returns and free cash flow and also just from a deleveraging standpoint.

So I was curious, Jay, if you could maybe just talk about how you're thinking about capital allocation between the 2 plays in 2020?

Gabe, 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 -- and lower rates, as we've talked about before.

So as we've said, we'll spend -- 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.

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?

Yes, Gabe, again, this is Herb.

So yes, we do see the potential to reduce costs further.

Obviously, we're in a deflationary environment, and then we are seeing different ways that we can get the same productivity with a slightly different completion design that helps out on the cost side.

So yes, we see the potential for lower.

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

Jay, my question, you guys continue to have -- you said the efficiency 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 again, a lot of times, there's always the argument of having to run the higher activity to stay more efficient.

But I'm just wondering how you all sort of view that.

Yes, Neal, this is Herb.

So we put together a program with activity for the year.

And then as activity -- as we're faster in executing, we're 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 and 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 3 to 2 frac spreads in October.

And we'll get all our activity and more for the same capital.

Got it.

No, makes sense.

And then just -- or to follow up on that.

The efficiencies that you're seeing, I mean, is it largely through just the longer laterals?

Is it continue improving the completion design?

I'm just wondering, anything else you can sort of shed on that, how you continue to achieve such great prices there.

Yes.

I would say it's all the above.

But the #1 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 really comes down to people that are out there doing the work.

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

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 we're going 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, pulling every knob 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 be a benefit for 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 as -- 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 wells better.

So we're going to do everything we can to get to 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 costs there.

Obviously, well-documented 10% reduction in the Midland.

Do you -- 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 where you can get kind of 12% off those costs?

Where do we sort of sit there?

Okay.

Leo, this is Herb.

So you've probably seen in previous earnings reports where 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.

We're not there yet, and I think your maturity schedule allows us some flexibility versus some peers.

But as you think about cash flow for 2020, if it's not forthcoming for 2020 and '21 as you're planning, what plans do you have for the '21 and '22 maturities?

What ways could you refi or extend those?

Yes, this is Wade.

I think you set it up well, that we do have some -- we have several years here to deal with this.

The first real maturity is not until the end of '22.

So I guess I would say that 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 on the revolver as well to use some of that, if needed, but there's just a lot of things that can change over a 2- or 3-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 we'll -- between now and then, we'll watch the capital markets, too.

Those could change.

But lots of flexibility.

I think we have more time than most of our peers, as you said, to deal with these.

Makes sense.

And 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 when the market cap is down from when those -- the existing ones are issued and other noncore assets as well?

Basically just trying to assess the reliance on the capital markets.

Yes.

No, 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.

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

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 aren't 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 towards the lower 2s area.

So a combination of those 2. And there are other possibilities.

I guess I'll let Jay talk about that.

Well, certainly, asset sales are 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.

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 costs to be lower in a general sense.

So 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 costs to be lower.

So in a general sense, I would say right now, we're assuming that our capital program will be smaller than it was last year in terms of dollar spend -- or I should say, this year.

2019 is still this year.

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

I was hoping maybe you could provide a goalpost for 2020 South Texas activity.

Compared to the 19 wells this year, are 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 to free cash flow next year.

Well, that's really 2 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're getting toward that time there in February where we guide, we'll tie that up.

We're going to do -- as we said earlier, we're very committed to the objective of achieving free cash flow next year.

We're really excited about the progress we've made in these Eagle Ford wells.

But free cash flow is our primary objective.

So we're going to do what we need to do.

Okay.

That's helpful.

And on the OpEx side, you made great progress on LOE.

Is 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 we're in a deflationary environment, and we are doing 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 as South Texas becomes a smaller proportion of total LOE, that, that kind of counters some of the additional savings we'll generate on the Permian side because it has such low LOEs.

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.

On the Eagle Ford, the results from the new JV design certainly looked encouraging.

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're really striving for is to get higher returns through longer laterals and the wider spacing.

And so that's what 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 will 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 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 Crédit Suisse.

On the offset 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, it's 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 get -- improve in the coming quarter 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 points they'll be drilling, and at what points 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.

So it's a 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 to date.

And then my follow-up, I know there's many questions on the free cash flow for 2020.

Eagle Ford activity is certainly an obvious lever to the CapEx budget.

But with tempering Permian activity be an option to that balance as well?

Well, Betty, it all comes down to returns.

And I think, clearly, we're looking to prioritize free cash flow because we want to prioritize absolute debt reduction.

So we're still working on a number of different alternatives, looking at various growth rates, how much free cash flow they generate versus how much free cash flow growth, debt adjusted per share type growth they generate.

We haven't gotten to the point yet where we can exactly say where we're going to land.

In general, we're moving more towards the direction of free cash flow and debt reduction.

But we'll give you official guidance on that after the first of the 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 and not suboptimize 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?

Well, we'll run strip.

We'll run the strip case.

And then -- as you know, we're very well hedged for next year, but we generally run strip cases for budgets.

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

Clearly, you're 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?

And 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 4 fully dedicated wells to date, and we're pumping Eagle Ford completions.

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 tool cadence 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'd need in a year.

I think it's pretty clear if you look at our third quarter results that 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 base has actually been doing a little better than we expected.

Got it.

And that is from downtime management.

I mean, is that -- or what is driving that?

And is there more room to -- it's, therefore, base production management?

Biju, that -- I would say that's a combination of us being conservative in our base production forecast and actually getting better uptime than planned and better well performance overall.

So there's 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.

With your reorganization that you're implementing, I 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 era in oil and gas?

Yes, Mike, that's a great question.

I think our -- 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.

When you look at our planned operations now for the next few years, we're going to be largely Permian-based.

And if you start to look at -- there's 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.

And 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 our -- the operations portion of our business.

So I look at it, I don't see this as an impediment to growth at all.

I think it's a normal streamlining that you would do given the situation we see going forward.

Now I'll also note that -- and I think it's important that people know, we cut our head count here by 1/3 over the last 4 years.

And so if you look at this cut and say, "Well, it's not that big a cut," and it's additional on top of the 1/3 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 giving up future growth here in what we're doing.

Yes.

And I'll add on that one that we 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 preserved that with the way we've reorganized.

Got it.

Some good insight.

I guess, obviously, you haven't formalized the 2020 plan.

You've had a lot of questions around 2020.

Just wondering, given that it's 80 to 85 [tills] to keep things flat, I assume you're still planning on base case at this point based on what you know that you'd still generate some growth next year?

Well, 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.

So other than that, we'll just have to leave that until we actually guide.

Understood.

Last one is just on...

Yes.

And 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's no issue with that, okay?

But how much and how much -- what happens in the Eagle Ford and 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?

Yes.

I assume you're asking because of the filing yesterday.

I mean, 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 filing on a number of other holdings, so -- but probably all we should say.

Well, they've held our stock for a number of years as a result of it.

We gave them stock during an acquisition, as you are aware.

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

I know guys have been working to optimize artificial lift in that -- a piece of the improvement in the LOE.

I was just wondering if you could talk about what that optimization entails.

And does that change at all the flowback of the wells?

Gail, yes, that's a -- there's a lot of pieces to -- the answer to that one.

But first of all, on an LOE side, when we're 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 a year, it's not really going to be very different.

So you'll see some little differences at 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's talking about the Eagle Ford, which was great this quarter, but I also thought 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 are Lower Spraberry or on the eastern edge of the asset, which typically has a lower IP and have lower declines.

So I was just curious if those Lower Spraberrys and their eastern edge execution was actually outperforming expectations or if you did anything different in the design there.

Again, yes, that is a great point.

There are some wells actually on the eastern edge of that.

We're performing extremely well.

And the Lower Spraberrys were mixed.

But wherever there's a lower IP, we tend to see the lower decline rates.

So they'll 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 Lower Spraberrys that have the opposite behavior.

So we're real pleased with the results there.

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

And at this time, there are no further questions in queue.

I turn the call back over 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.