SM Energy Co (SM) 2018 Q4 法說會逐字稿

Good morning.

My name is Jodie, and I'll be your conference operator today.

At this time, I would like to welcome everyone to the SM Energy's 2018 Results and 2019 Operating Plan Q&A Conference Call.

(Operator Instructions)

Jennifer Samuels, Vice President of Investor Relations, you may begin your conference.

Thank you, Jodie.

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 our website for this call and the Risk Factors 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 most directly comparable GAAP measures 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 Michael Scialla of Stifel.

When -- you mentioned in both the prepared remarks and in the release that one of the goals here is to reach free cash flow in the second half of '19 and sustainable free cash flow and growth beyond that.

Just wondering how you're looking at -- 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?

Yes, it's -- Mike, it's Wade.

It's a -- 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, yes, continue to generate free cash flow.

Okay.

And looking at 2019 specifically, the -- looks like the first quarter CapEx is higher than the rest of the year.

Just wondering -- I know you're adding a sixth rig.

But looking at your Slide 29, it looks like completions are actually lower in the first quarter.

Just wondering what's driving the bump in the CapEx there?

Yes.

Mike, this is Herb.

So it's really -- the way to look at it is 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 -- quarter-to-quarter, it just depends on how many completions we actually put in the ground in the first quarter and the pace.

And if you looked at last year, our pace was more rapid than we had budgeted.

This year, hopefully, we've increased the pace and the budget quite a bit.

We'll see where we actually come in on that one.

But the split quarter-over-quarter, it's going to -- it's really, I'd look as first half 60%, second half 40%.

Okay.

And then last one for me.

I just wanted to ask about the Chalk, looks like a pretty interesting well that you have there.

How are you thinking about that?

I know it's been viewed traditionally as more of kind of a conventional or a play that relies on sweet spots at least relative to the Eagle Ford.

Any thoughts?

I know you just got results on 1 well so far, but maybe what drove you to that particular location?

And how widespread do you think the play could be?

Right.

Well, it is -- on Austin Chalk, actually we're pretty happy with what we've seen, and we actually have more data than just that 1 well.

We have partial penetrations.

And I think I showed 3 of those on the map.

And then, we have one that's almost entirely in the Chalk to the Northwest.

And then this was our first really where we dedicated and got a lot of data.

And we were really happy to see yields of 2 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 lot of penetrations in the Chalk.

So we're looking at it as having quite a bit of upside, but we're not going to count it all in there yet because we want to get more wells.

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.

Your next question comes from the line of Oliver Huang of Tudor, Pickering.

Last night's deck 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 4 to 5 zones and 2 to 3 in the other half.

Could you all walk us through that comment from an aerial perspective?

And also, if there is any sort of risk getting factored into your locational count?

Okay.

Oliver, this is Herb.

So let me go over that.

So the number overall is real similar to what we showed last year, where it's just 1 year less of completion.

But it's -- we look at the traditional 3: Lower Spraberry, Wolfcamp A and Wolfcamp B. Then there's been considerable offset activity in the Middle Spraberry and Wolfcamp D, primarily on the west side.

So there is also Dean.

So when we say 5, it's generally the 3 plus Middle Spraberry and Wolfcamp D in some of the areas, mainly on the west side.

And then you move east and you go to areas where there's 2 to 3. And that's really the basis for those aerial distributions that we've got there.

And then the risking side, these are showing basically certain spacing levels, which we don't risk because of how much well control we have around this.

If you looked at how much drilling had been done in Howard County in 2017, 2018, it's really quite well derisked.

There is a little -- we obviously have wider spacing in the intervals that have less data like the Middle Spraberry and the Wolfcamp D. Does that help out, Oliver?

Yes, that's perfect.

And for my follow-up, I was just wondering if you all have a blended ROR for your remaining inventory at call it, $55 WTI and $2.75 Henry Hub or whatever deck you have readily available in the Permian?

And also what 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 would be slightly higher than the Eagle Ford, but that's really how it looks.

And does the longer-term inventory that you all have mapped out changed drastically from what you all are drilling in 2019?

No.

I mean, the mix will change.

We don't have much in '19 in the way of Middle Spraberry or Wolfcamp B or Dean, but we'll have more of that later as time goes on.

Returns-wise, the methodology, we are totally returns-focused.

And we're only designing DSUs with -- where that last well in the spacing decisions, there's 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 NPV10 type of methodology.

We really want that 25% return on the last well drilled.

(Operator Instructions) Your next question comes from the line of Paul Grigel of Macquarie.

Maybe following up first on kind of into 2020.

On Slide 29, you guys show DUCs building into year-end with a 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?

Yes, I mean, I remember the DUC count from year-end '18 going to year-end '19, it's just slightly lower.

It's actually quite similar.

It's the timing.

So 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 of the focus is in the higher oil cut of Howard County throughout the year versus kind of increasing throughout the year, maybe the cadence there?

Yes, it's pretty straightforward.

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 where -- because of where we're drilling in the Eagle Ford.

So that's one component of the change.

The other is the Permian program overall goes from 79% oil in 2018 to 78% oil in '19.

And all of that is just a little bit of where we're drilling, but primarily, it's just that normal slight GOR increase that you get as time goes on with the wells.

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 PDP decline rate handy?

It's in there.

It's in there also.

So you'll see that on the -- Eagle Ford side, I think, it's 29% the first year and the second year, I've got -- I put it on the remarks yesterday.

Your next question comes from the line of Michael McAllister of MUFG.

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?

Yes.

And 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.

While -- our goal is to get leverage down into the 2x area.

So get it -- 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'd be both.

Yes, it'd be reducing absolute debt and growing cash flow at the same time.

So obviously (multiple speakers)

Sure.

Got it.

Yes, the combination, but I just wanted to know it on the absolute level.

So let's say, we get into an environment where the oil price goes up higher and you are as efficient as you were in 2018.

Would an -- you could accelerate that by increasing CapEx and increasing activities to get the 2020 to hopefully get to a bigger base.

How do you balance that with the idea that you -- is, 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 there?

I think absolute debt reduction would be the goal first and -- versus the temptation of accelerating and outspending a little bit more.

We want to maintain the levels of outspend 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.

Your next question comes from the line of Stark Remeny of RBC.

I was just hoping you might be able to provide some clarity around your natural gas processing force majeure in the Permian.

When do you expect a final resolution?

And do you have any commentary on when you -- or what the level of impact is factored into the first quarter guide?

Yes, Stark, this is Herb.

So the force majeure event we mentioned in the fourth quarter, they were 2 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, there is some flexibility around that, sometimes can take a little bit longer, but just through middle of February, we basically see about a 200,000 barrel equivalent impact from that plant alone, 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 around 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 initially, we did quite a bit of data gathering, and we're real pleased we did our first permanent fiberoptic installation.

We got a lot of data that really helped us optimize the completion design with -- together with the JV partner.

We also started putting the wider-spaced wells in.

So as we get into 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 the data.

There is a lot of data analytics going into that.

Looking forward, we'll see where things go on, 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.

Your next question comes from the line of Michael Scialla of Stifel.

Yes, 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 wells in...

Are you talking drilling or completing?

Well, both.

Oh, okay.

Well, there is a little bit of difference there.

But yes, there is -- I'd say, for our 100% wells, there's more on Galvan Ranch than Briscoe Ranch, so more of the Eagle Ford East than the Eagle Ford North, although there are some Eagle Ford North ones.

And are those Eagle Ford North wells primarily to save acreage?

Or do 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 the -- your spacing.

You said 770 feet in the Midland within zone.

I think you'd 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?

Yes.

So for our 2019 program, the range is 420.

So we have some 420s within zone and all the way up to 1,320 within zone.

And so the 770 is just an average of the entire program.

And there is a number of areas where we're holding acreage and we're spacing wells at 660 to 880 where we do 2 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 -- in some cases, you can almost -- not quite stacked, but stacked over each other, but we're not counting it that way.

We're just counting it just within zone.

Does that make sense?

Yes.

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 we have so much data now that we can really hone in on that fundamental conclusion of getting those returns at 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 look like a good estimate at least for the western acreage at this point?

Yes.

Depending on where it is and 1 of 2 intervals, yes, 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 higher return, that's the sort of evaluation we'll do.

Okay, and then just had one more.

On your proved reserves, just some nice additions but you also had revisions of 69 million BOE.

Was that price-related or any performance-related revisions in there?

So no, that's -- 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 in our revised development plan, we eliminate some PUD locations, and we deem that PUD removal a revision.

And that's kind of what you've got in those 69 million barrels.

Also in some cases, with the higher returns from those wider-spaced wells, we'll actually move some of the existing PUDs out of the 5-year horizon.

So then, we call that -- because of the 5-year rule revision.

And that's in those 69 million barrels.

So it's -- most of the revision is in the Eagle Ford and from -- related to the development plan.

There are some smaller ones in the Permian, but that's -- the key thing is really the development plan in the Eagle Ford.

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.