SM Energy Co (SM) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the SM Energy 4Q and full year 2016 earnings conference call.

At this time, all participants are in a listen-only mode.

Later, we will conduct a question-and-answer session and instructions will be given at that time.

(Operator Instructions).

As a reminder, today's conference is being recorded.

I would now like to turn the call over to Mr. David Copeland, General Counsel.

Sir, you may begin.

Thank you, Chelsea.

Good morning to all joining us by telephone and online for SM Energy's fourth quarter and full year 2016 earnings conference call and operations update.

Before we start, I would like to advise you that we will be making forward-looking statements during this call about our plans, expectations, and assumptions regarding our future performance.

These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted on our website for this call, and the Risk Factors section of our Form 10-K that was filed this morning.

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 earnings press release from yesterday.

Other company officials on the call this morning are Jay Ottoson, President and Chief Executive Officer, Wade Pursell, Executive Vice President and Chief Financial Officer, Herb Vogel, Executive Vice President-Operations, and Jennifer Samuels, Senior Director-Investor Relations.

I'll now turn the call over to Jay.

Well, thank you, David.

Good morning, everyone, and thanks for being with us today.

Yes, I think everybody who has followed us would agree that we're a very different company than we were a year ago.

There's an illustration of that on slide three which shows you a summary of all the transactions we accomplished since the middle of last year.

In everything we've done, our objective has been to build a strong and resilient company that's a premier operator of top-tier assets, and by doing that, to put ourselves on a path to deliver long-term differential performance for our shareholders.

It has been incredibly exciting to be part of this transformation.

But it's been even more exciting putting together our plans now for the next three years and just looking at that performance that we believe that we can now deliver.

And that's what we're going to talk about this morning.

So with that, I'm going to turn the call over to Wade and Herb so they can run through our plans.

Wade.

Thanks, Jay.

Good morning, everyone.

Yes, I'm very excited to share with you the specifics of our three-year plan this morning.

Let me first say that in regards to the fourth quarter and full-year results, I think the press release and 10-K provide more than ample discussion in detail.

So I'll not spend any time on that today.

I'm going to focus on the future this morning and walk through the three-year plan which we're so excited about.

So let's get started on slide four with a preview.

The reason we're so excited about this plan is pretty simple.

We're going to be generating astounding production growth in arguably the best, highest-margin basin in the country.

So we're talking about a compounded annual growth rate in the Midland Basin approaching 100% over the next three years.

By the time we get to 2019 as a company, we'll be generating significantly higher margins even in a flat oil price environment.

We'll be growing year-over-year production in 2019 at least 25% within cash flow and have a strong balance sheet with around two times leverage.

It's hard for me to imagine that not driving differential returns for our shareholdes, and that's our objective.

Obviously, you can't have a three-year plan without a first year.

So our four major priorities in 2017 will be -- first, we'll be accelerating our activities in the Midland Basin and doing the groundwork to prepare for further acceleration in 2018.

This means that we will focus much of our effort in 2017 on completion and spacing optimization testing getting it ready for the high-density development.

Herb's going to get into this later.

Second, we'll be strictly prioritizing our capital spending on our top-tier Midland Basin asset and our top-tier operated Eagle Ford wells.

Third, we expect to complete the sales of our non-op Eagle Ford asset and our remaining assets in the Bakken.

And then fourth and finally, we'll utilize these proceeds to reduce debt levels, strengthening our balance sheet.

So with that overview, let's get into the details.

Moving to slide five, I'll discuss some general assumptions in activity levels.

You can see that during 2017, we will average around six rigs in the Midland Basin and one to two rigs in our operated Eagle Ford.

Moving to 2018, we further accelerate by jumping to 11 total rigs in the Midland Basin while maintaining the one to two rig pace in the Eagle Ford.

The important point here is we plan to complete 80 wells in the Midland Basin and 35 in the Eagle Ford in 2017.

That rig count in 2018 and 2019 could vary, i.e., it could to be lower, as we gain further efficiencies.

And with respect to commodity prices, we are simply assuming our recent strip.

A lot of folks have been asking about service cost assumptions.

Based on what we see and given these commodity price assumptions, we have assumed completion costs to escalate during 2017 up to about 10% increase by the end of this year.

And then they stay there in 2018 and beyond.

We essentially assume that if there were any other increases including drilling, we would absorb them with efficiency gains.

So let's move to slide six and look at the projected results from this program.

As we look forward, I think it makes the most sense to focus on retained assets.

That would be the Midland Basin in the green and the operated Eagle Ford in the blue.

Now the first thing that should jump off the slide is the very significant growth in the Midland Basin over the next three years.

As I stated earlier, that's a compounded annual growth rate approaching 100%.

On a side note here, you might remember a slide that we showed you late last year after announcing the QStar deal.

In it, we predicted some fairly impressive Midland Basin production numbers for 2017 and 2018.

Based primarily on well results since then, these numbers that we're showing you today are actually 15% to 20% better than those previous numbers.

Very exciting indeed.

So our total production will grow at a compounded annual growth rate of at least 15%.

And the real important point is in 2019, it will be growing at least 25% that year within cash flow.

Now, with respect to 2017, I think I should point out that a lot of analysts are keeping the Divide County production for the full year until a sale is announced.

We have removed Divide County production beginning July 1, 2017, assuming the asset has been sold at that point.

Also, we're now assuming the non-op Eagle Ford is sold at the end of this month.

And consequently, its production is removed from our model beginning March 1, 2017.

You should factor that in when thinking about our reported guidance for 2017, which is a range of 40 million Boe to 43 million Boe.

And that brings me to slide seven.

You'll be happy to hear that I'm not going to bore you by reading through this slide.

We'll certainly take any questions you might have on it later in Q&A, or feel free to call us later.

One point I will make though, is that we are guiding to oil percent of 29% in 2017.

You'll be happy to know that as Midland Basin production grows over the next three years, this percentage will also grow steadily through the period to around the mid-40% level by the end of 2019, mid-40s.

That translates to significantly improving margins during this period as you can see on slide eight reflected in the black line.

Our total company operating margin per Boe produced in the fourth quarter of 2016 was around $12 per Boe.

That number will rise to around $23 per Boe in the fourth quarter of 2019.

And that assumes again a pretty flat commodity price environment.

Now this is certainly a shrink to grow strategy we're executing and that inevitably comes with a period of investment or outspend.

That's going to be 2017 and 2018 for us.

In total, about $800 million for the two years combined.

However, please note the significant amount of cash flow on this slide being generated when we get to 2019 and are growing the high-margin production.

There's also good news on the next slide, slide nine, divestiture proceeds from the non-op Eagle Ford and Divide County sales will more than cover this outspend, allowing us to also reduce debt levels and maintain significant liquidity during this period, which brings me to slide ten and the balance sheet.

We ended 2016 with total debt of just under $3 billion.

All of this debt is unsecured.

All of this debt has no financial covenant and the earliest maturity is 2021.

We have zero drawn on the secured revolver, so we end the year with lots of liquidity.

That borrowing base is currently about $1.2 billion.

And with the divestitures, I certainly anticipate it declining somewhat here in the short term.

But I also don't anticipate us needing to draw on it either outside of some strategic purpose.

Turning to slide 11, I mentioned in my opening remarks that our three-year plan not only results in year-over-year production growth of at least 25% within cash flow in 2019, but also delivers a strong balance sheet and with total leverage of around two times by the end of that period.

You see that progression on this slide in the black line.

That's a great place for me to finish.

I'm now going to turn the call over to Herb to drill deeper into our exciting assets, which are going to deliver these excellent results we've been discussing.

Herb.

Thanks, Wade, and good morning to everyone on the call.

Wade did a nice job laying out the step-change, production growth, and margin expansion we see in each of 2018 and 2019 -- that, in turn, generating a doubling of cash flows from 2017 to 2019 under our plan assumptions.

I'm going to speak now to the nuts and bolts of our 2017 operating program that really position us for that trajectory.

There are really four key objectives underlying our 2017 program.

First, we're going to drive aggressive growth in the Midland Basin, which in turn better balances the portfolio in terms of commodity mix and drives margin expansion.

As shown in slide 12, our 2017 capital program allocates approximately 80% of total capital spend to the Midland Basin.

Second, we'll be focusing Midland Basin capital investment on drivers of value creation, factors that optimize well performance, recovered resource, and NPV per section.

Third, we'll position the company to run a much larger optimally-designed drilling program in 2018 and beyond.

And then fourth, of course, will be building reserves and inventory.

So today, what I'm going to cover is the individual objectives of each of the Eagle Ford and Midland Basin programs, along with an update on recent well results.

I'll then go over well economics behind our 2017 program, where you'll see the top-tier returns from both the Midland Basin and from the Eagle Ford programs.

And finally, I'll discuss our views of inventory including progress already made in the Midland Basin.

So turning to slide 13, let's start with the Eagle Ford since it deserves some of the limelight.

Here, we're going to focus on completing high-return wells.

The program includes running one rig through most of the year with the second added in September.

We plan to drill about 25 gross operated wells and complete about 35 wells, which will support our leasehold obligations and our marketing commitment.

Over 60% of the completions will be on our eastern acreage.

Putting together what we've learned from our 2015 and 2016 pilot programs as well as looking at offset operator data, the 2017 drilling program will include longer laterals averaging about well over 8500 feet.

Our completion program will include tighter stage spacing and about 2000 pounds a foot of proppant loading.

And we'll really be focusing on the high-return DUCs or the high-return, high natural gas and NGL content areas in the Eastern Eagle Ford.

I'll note one impact to the timing of some of our Eagle Ford production through the quarters this year.

An offset operator will be embarking on an aggressive mow the lawn completion program just across the lease line from an area where we have significant production.

We will be coordinating with them and shut-in our nearby wells for a few days before and several weeks after they start their frac program.

This is expected to reduce production directly due to the shut-ins and then can potentially result in lower hydrocarbon production for a couple of months before wells return to their original decline behavior.

Turning to well results.

First, in the Eagle Ford North, we now have six months of production and flowback data from Pilot 7 in the northern part of our acreage shown in gray on the map.

As you may recall, this is by far our most aggressive and intensive pilot.

The objective was to assess with fully bounded wells what our maximum inventory potential could be.

Complete success with this pilot would really triple our earlier view of potential inventory in this area.

And this 24-well pilot includes lateral length of 6800 feet to 7200 feet in a stacked and staggered configuration, very tightly spaced with 350 feet between lateral, and 19 wells were planned with less than 100 feet apart vertically.

Analyzing the production data over the past few months, we concluded that with our current completion design, the gassy nature of the production in this area and this tight spacing, that communication between wells resulted in suboptimal economics at current commodity prices.

However, we were really pleased to see good Lower Eagle Ford well performance and higher condensate and NGL yield in the Upper Eagle Ford.

After reviewing the results from these northern area wells and earlier offsets, we will move our base configuration for this area to 625 feet between Lower Eagle Ford wells staggered with Upper Eagle Ford wells spaced 1250 feet between laterals.

This looks to be optimal for this area at current commodity prices.

In addition, based on analysis of our own as well as at offset operators' recent wells, we will modify our well design to 10,000-foot laterals, around 150-foot stage spacing, and 2000 to 2500 pounds per foot sand loading.

We're going to plan to implement this in this area over the next couple of years.

And for those of you who follow state-reported production data, for the third quarter of 2016, you would have noticed lower per well gas rates in this tightly spaced pilot and a higher oil percentage as a result of the Upper Eagle Ford contribution.

And I should also note that state data is two stream, not three streams.

And it really doesn't normalize out days offline.

Now, moving to Eastern Eagle Ford on slide 14, here we're showing cumulative production per 1000 feet of lateral from among another 24 wells after about 1.5 years of production compared to the type curve previously developed from wells with 900-foot spacing.

So let me be clear on the point we're driving towards here with this slide.

We are showing production from new wells at tighter spacing and comparing to a type curve with wider spacing.

Shown are average production performance of 13 Lower Eagle Ford wells spaced at 625 feet in one area, shown in green on the map in the previous slide, and then a total of 11 staggered Lower and Upper Eagle Ford wells spaced at 625 feet within each zone, shown in blue in the previous slide.

As you can see, these wells, co-developed at tighter spacing, continue to outperform the type curve on a per lateral foot basis.

This supports the conclusion that our staggered Upper and Lower Eagle Ford configuration with 625 feet between wells within a zone, or if you look from a plan view or from above, half that, 312 feet between wells and that optimizes the value of our acreage.

These are great wells and they are at tighter spacing.

They deliver the top-tier returns that we're looking for.

And very importantly, they also maximize the NPV per section of our acreage.

And for more of this, finally turning to six wells that were completed earlier in the fourth quarter shown in orange in the map on the previous slide, we have more than 90 days of production on these wells staggered again between the Lower and Upper Eagle Ford as shown on the right side of slide 14.

We completed these 7600- to 8100-foot laterals with sand loading of 2000 pounds per foot, with half at tighter stage spacing.

We were pleased to see excellent productivity.

These have 30-day IPs of over 12 million cubic feet per day on each of these wells.

And that's over 2000 Boe per day per well.

Upper and Lower Eagle Ford had very similar deliverability in this area initially.

And again, a great set of early results for the staggered configuration.

Now turning to slide 15, I'll turn to the Midland Basin and cover our operating plan objectives there.

Here again, we'll be focusing on optimizing our drilling and completion technologies to prepare for significant acceleration in 2018.

We currently have four rigs running and we'll add one more in March and another by early April to get to six for much of the remainder of the year.

We currently have two frac crews completing wells in the basin.

As Wade mentioned, we plan to drill approximately 100 gross operated wells and complete approximately 80 gross operated wells.

We believe this will drive phenomenal growth in Midland Basin's production in 2017 over 2016 and set up a continued high-growth trajectory for both 2018 and 2019.

In terms of where these are, we expect more than half of our completions to be on the RockStar acreage, about 75% of completions will be in the Wolfcamp A and B, and 25% in the Lower Spraberry and other.

Recognizing the greater NPV as we've shown several times over the last six months of longer lateral, lateral lengths are expected to average 8700 feet in Sweetie Peck and 9500 feet in RockStar.

And then to best benefit from cost efficiencies, the majority of wells will be on three to six well pads.

On the RockStar acreage, approximately 60% of our capital program will be dedicated to drilling and completing wells and optimizing spacing on the confirmed acreage positions we highlighted during our January 31 investor call.

The remainder of our capital program will be directed to delineation of the unconfirmed sweet spot areas, enhancing completions, and gathering data on additional intervals.

Now, on slide 16 and 17, I won't go over them in a lot of detail, but they provide updates on the new wells we presented a few weeks ago, all of which now have 30-day IP rates.

All wells, including the new wells on the eastern part of our acreage, continue to exceed acquisition expectations and that 1 million barrel equivalent peer type curve that we showed previously.

Now I would just have to say just take a look at that Blissard well on slide 16.

What a well.

It kind of speaks for itself.

Next, I'm going to turn to the economics, and the average well economics behind our Eagle Ford Basin and Midland Basin plans, and that's slide 18.

As a reminder, we have built in completion cost increases, as Wade mentioned, of about 5%, which assumes an approximate 10% increase by year-end.

We have several different contracts in place, which mitigate our exposure to cost escalation in the first half of the year and longer for certain specific services.

Again, starting with the Eagle Ford at the bottom of the slide, at recent NGL price levels, we can achieve top-tier returns of over 50%.

I don't know whether people realize or recognize how much value there truly is from the high NGL yield produced by our Eagle Ford operations and how our drilling program there can deliver top-tier returns.

The economics we are now showing reflect a longer lateral length of 8000 feet and tighter stage spacing that we have been implementing.

The underpinning type curve for these economics assume 625-foot well spacing, well cost average $6.2 million.

And of course these would be staggered between the Lower and Upper Eagle Ford.

In the Midland Basin, we are able to generate returns of around 70% at $55 oil, and higher for longer laterals.

Examples here are representative of our program and show Sweetie Peck, Lower Spraberry economics with 7600- and 10,000-foot laterals and RockStar, Wolfcamp A economics with 7600- and 10,000-foot laterals.

We've incorporated improved production performance from tightening our stage spacing to 167 feet with our latest frac design and increase in the well cost accordingly.

So now let me review drilling inventory, and turning to slide 19.

Our current total potential drilling inventory for the operated Eagle Ford and Midland Basin core retained asset is more than 5500 gross operated locations or more -- almost 50 years our current annual completions pace.

If you doubled our drilling and completions pace going forward, you'd get nearly 25 years of drilling inventory.

The green bar shows approximately 2000 wells in our current year of drilling inventory, which we believe would hurdle a 20% IRR threshold at five-year average strip pricing, largely based on type curves derived from existing wells.

In grey, we show about 3500 additional potential well locations.

Adding the 3500 and 2000 gets the 5500 total I just mentioned.

We fully expect that successful delineation of wells, successful spacing tests, and completion of design improvements would progressively move the inventory shown in grey into that economic resources category shown in green.

In fact, and Jay reminds me of this every day, it's our job to do that and we focus on it every day.

I have to say that it is truly amazing what new technologies have enabled.

Given our track record within several basins, I would never bet against future technology improvements bettering our returns and increasing our economic inventory.

In the bar chart, Eagle Ford inventory is roughly unchanged from last year's 780 gross operated locations, less the 45 completions in 2016.

Add our planned 2017 completion space, that's more than 20 years of inventory in the Eagle Ford.

Now, let me turn to the Midland Basin inventory and that's shown on slide 20.

Here, we're already growing inventory.

Our view of economic locations increased from approximately 1000 just last October to approximately 1200 currently.

The increase is based on performance of wells we, and operators who are directly offset, have completed since October.

The economic inventory, shown in green, represents wells that are located within the contours confirmed by horizontal drilling that we showed during that investor call on January 31.

These include a maximum of three intervals and are based on wells with historical sand loadings of around 1500 pounds per foot.

I should add that on our RockStar acreage, we do not assume well spacing any tighter than 660 feet, equivalent to eight wells per section per interval within the green economic inventory.

With successful delineation beyond those contours we showed in those maps before, we see additional inventory pulled in from the grey bar.

If tighter spacing is also confirmed, we'd also be pulling in more inventory from the grey bar to the green bar.

So let me just summarize by saying we're really excited about this 2017 program.

We know we have top-tier assets.

And as described by several third parties, we are a premier operator in terms of delivering best-in-basin wells.

We're very focused on execution and look forward to delivering on our plan objectives and progressively converting more of our substantial drilling inventory to prove reserves over time and with high return.

With that, let me turn the call back over to Jay.

Jay.

Well thanks, Herb.

I mean wow, right.

You look at this presentation -- and I've seen it a number of times --and I just can't get over how big a difference this is from a year ago or two years ago in terms of just everything about our company.

We got a solid plan for 2017 and it's really focused on maximizing value, setting ourselves up for this big growth trajectory that we're on, really the next big step in transformation of the company.

We'll get some of this noise behind us associated with all the asset sales.

Then over the next several years, even in a flat oil price environment, we're going to rapidly grow high-margin production that's going to accelerate our cash flow growth.

As we said, I'm doubling cash flow over the next couple of years.

And that propels us to a position where we'll be growing rapidly within our cash flow with a strong balance sheet.

All that is made possible by this much-improved portfolio and we're very confident that we can continue to grow our economic inventory.

Now, I don't know how you can't be excited about the future of this company.

I've just never been more convinced than I am today that we're on the right path to create differential value for our shareholders.

So with that, we'll take your questions.

(Operator Instructions).

And our first question comes from the line of Welles Fitzpatrick with Johnson Rice.

Your line is now open.

Hey.

Good morning.

Hey, Welles.

Hi, Herb.

I think you said that 25% of the spending was going to be in the Lower Spraberry and other.

Does that imply that you guys are looking at doing a Middle Spraberry or a Wolf C test this year?

So Welles, just on that percentages, those were of the completion.

That's the completion count, not the dollars (inaudible).

And you're right, 25% across Sweetie Peck and the RockStar area.

That's 25% in Lower Spraberry.

And then the question is whether we've got others.

We're going to be getting a lot of data in other zones.

And we haven't finalized when we'll actually get completions done at the back end of the year when we get the data from the data acquisition program we've got laid out.

Okay, perfect.

And then on slide 18, on the Eagle Ford East returns, could you give any indication?

I know it's preliminary, but what that 60% might move to with the 10,000-foot laterals?

Is that going to be a significant bump to those IRRs?

Okay.

So the 60% is the -- are you talking about the returns, the IRR?

Yes, that's right.

Yes.

I wouldn't venture a guess on that one yet.

We'll put the 10,000-foot laterals out there.

But we know there is a scale-up factor that's pretty substantial when we go from 7600 to 10,000 foot in other areas.

So generally, it's almost one-for-one on the contribution for IPs and EURs as you go longer.

When you start getting into the 10,000 foot, we just have to confirm that that's true.

Okay, perfect.

And one last one and this might be a little Q2.

But on slide nine, kind of looking at that bar chart, should we take that as soft guidance that you guys are looking for some plus or minus $450 million for Divide?

We're not giving guidance on that.

Obviously, we're not going to sell it unless we get something significantly higher than our leverage.

And you know what the cash flows roughly are there.

So we don't like to quote numbers during the sale process.

Okay.

But we've clearly realized more in these sale processes than I think most people thought we would and probably more than we thought we would.

There's clearly an appetite for these and these are good assets that have drillable inventory in them.

They just don't fit now in our much-improved portfolio and I think that's the key thing here.

We just looked at it and decided based on what we have to drill, these assets will not attract capital from us.

But they will attract capital from a lot of people and are great assets for startup companies.

That's the kind of people we would expect to be interested in it.

Yes.

It makes sense, especially with the big jump up in returns in the legacy Eagle Ford.

Well, congrats and thanks.

Thank you.

And our next question comes from the line of Jeb Bachmann with Scotia Howard Weil.

Your line is now open.

Good morning, everyone.

Good morning.

Good morning, Jeb.

Just a couple of quick ones, mostly on Howard here.

Just I'm looking at the DUC count and kind of where you guys are building towards the end of this year.

It looks like, as you mentioned, the DUC is going to be going down in the Eagle Ford for me and it'd be going up in the Permian.

Just curious if that increase in the DUC count in the Permian is really infrastructure-driven, just a lack of takeaway or the need to build out at this point?

No.

Jeb, this is Herb.

The driver of that is the ramp-up in the rig count when we're going to six-well pads.

And as we get that further in 2017, there's going to be more and more six-well pads.

So as you can imagine, to drill up a six-well pad takes about 120 days.

So you got six wells.

If you have three or four rigs running on six-well pads, you can see why the DUC count really increases.

And that happens as you ramp up rig count.

Okay.

So I guess --

There's no infrastructure constraint, whatsoever.

All we have to do is put the tank batteries in place, and that's just on a schedule to put those tank batteries in place.

Okay, great.

(inaudible) infrastructure there.

Okay.

And the second one.

I was just kind of looking at -- if you can remind us where the drilling commitments are in Howard.

And I guess, are you guys going to do any work on that northeast acreage this year?

Okay.

Well, let me just say that the commitments there -- it's a large lease program out there.

So they'd have varying timings on when we have to drill on the different leases and there is different ways.

In some cases, you can extend.

But generally, we've laid that out with our expiry program on the leases.

But I'm glad you asked about that northeast block.

And we've been surprised how much attention it gets for -- it's only 14,000 net acres.

So that's around 15% of our Midland Basin position.

It's a lower working -- quite a bit of it is actually non-op also.

So we risked that area quite a bit more heavily in the acquisition because there's fewer horizontal wells as I showed on those January 31 calls.

So what we're really trying do is maximize our value and our returns throughout our entire program.

So yes, we'll have the Viper well, which you guys are aware of.

And that'll be completed over the next several months.

And then we'll have a couple more wells there by the end of the year.

But our focus again is on returns and doing a logical program through all the intervals and confirming the completion design throughout.

Thought I'd just note there's a good Wolfcamp B well right in the middle of the acreage.

And people tend to just ignore it for some reason or another.

I don't really understand that.

So we'll be testing at several different intervals there.

Yes.

That's actually an Eastland well, which is a short lateral, a little bit older completion design and still had a great (inaudible) and it's actually got a nice decline too.

All right.

I appreciate it, guys.

Thank you.

(Operator Instructions).

And our next question comes from the line of David Tameron with Wells Fargo.

Your line is now open.

Good morning.

Hey, David.

Can you just help me out -- the Eagle Ford completions and maybe you mentioned this and I missed it.

But kind of what does a typical job look like now?

I know you talked about the longer laterals, but what does a typical completion job look like in the Eagle Ford?

Okay, yes.

For the Eagle Ford, in the East, really it's 8000-foot laterals.

On the West, it'll be 10,000-foot laterals, 2000 pounds per foot of sand loading.

We'll do a few up at 2500.

And then the key change is stage spacing using mechanical diversion down to the 150-foot level.

And we'll be trying a little bit even tighter than that and a little bit wider than that.

But that's the fundamentals behind what we're doing.

Okay.

And is that -- I know the longer -- is that a change from what you have been doing or -- like in the last, let's just say in the last quarter or so?

Since the last quarter?

No, those wells that I showed you, the ones in orange on that map, half of them are at the 150-foot stage spacing and half are at 300-foot stage spacing with diverters, chemical diverters.

Okay, that's it.

But they're at that 2000 pounds per foot level.

Okay.

And then back to the -- I guess thinking about the corporate big picture, you guys mentioned -- I think you mentioned 25% within cash flow in 2019.

Yes.

What price deck are you guys assuming for that and --

That's basically strip.

Yes, that's --

That's strip, okay.

And then how do you --

(inaudible).

Go ahead.

Hold on, David.

Let's let Wade answer to make sure --

Yes.

The one thing I'd say to that, Dave, is, A, it's at a recent strip, and B, make sure you heard the words at least 25%.

No, that's helpful.

That's good.

So do you guys have any desire to hedge, to lock anything in 2018-2019?

Well, we certainly look at 2018 and 2019 as part of our regular hedging program.

So the answer is, yes, maybe.

The further out we go, a flat strip is a little more risky I think because cost could go up when you're talking that far away if oil prices go up.

But we certainly look at it.

And with respect to the bases in the Midland, we're certainly keen to look at that as well.

Okay.

And then last question, whoever wants to take this.

There's obviously concern from what everybody is calling the new entrants into the Permian.

Yourselves and some of your competitors that have recently -- well, that have made some big acquisition purchases in 2016.

And there is some concern that when you go to ramp your program mid-year, your breadth of service capacity won't be there, or you're last in line, or however you want to phrase it.

I'm sure you guys have heard that question time and time again.

Can you address how you're thinking about that over the next year, kind of the hurdles for you guys ramping in the basin?

Yes, David.

This is Herb.

First of all, you know what, we're not new in the basin, right.

We've been there for over a decade and we have great contracts with key suppliers.

So you just step through every single area, the rigs, the completion, the frac spreads and the facilities, the steel, the tanks, that sort of thing.

We've got schedules laid out there.

They're aware of what our ramp-up plans are.

We're engaging on a continuous basis.

We're in the community, right.

So we're way ahead of it in terms of making sure we got everything in place.

And you could see how smoothly we ramped up so far.

And we worked with several different providers where it's not all being done with one rig company.

It's not all being done with one frac company.

So I think you'll see companies really like working with our guys because they've got a great program.

You guys want to add anything else?

No, it's not -- Dave, I understand why you asked the question and I think it's not an unreasonable question.

But we've got a great program and people.

We have a great reputation down there and it's not a concern.

Yes, no.

It's a perception that's out there, Jay, obviously.

So I just wanted to --

Sure.

And again, I understand it.

I understand why people ask the question.

But I think people need to understand.

We've been there a long time.

We know everybody.

We've been preparing for a while for this.

And we wouldn't be putting these big numbers out here if we didn't think we could do it because that would be really dumb.

Fair enough.

So we really feel like we can do this.

All right.

Thanks for the color.

Thank you.

And our next question comes from the line of Chris Stevens with KeyBanc.

Your line is now open.

Hey.

Good morning, guys.

Just had a question on the Viper well.

Is that first one on Wolfcamp A?

And I noticed you guys permitted another well right next to it.

Is that going to test the Lower Spraberry so you basically have all three zones sort of de-risked this year?

And did I hear you correctly that the first Viper well will be completed here in the next couple of months?

Yes.

Chris, this is Herb.

So yes, the Viper well is a Wolfcamp A well.

And yes, by the end of the year, we do plan to have Lower Spraberry and Wolfcamp B tests out there.

And Jay mentioned earlier for one of the questions that Apache Eastland well is right there.

We also have -- just to the west, there's some great wells operated by Legacy that were Lower Spraberry and Wolfcamp A. And then you're probably aware there's a couple of other wells from another offset operator just to the west of our acreage.

And then there is Hannathon drilling to the southeast.

And I showed in January 31 a map of where all the rigs are in Howard County.

And you can just see how far operators are expanding just based on the mapping and all the additional data that people have out there.

I think that -- did that cover all of it?

Yes.

Chris, we're not going to get into too much detail about exactly where we're drilling because frankly there's still open acreage in some of these units.

And if you start putting sticks on a map for people, then you just create competition.

So we're not going to do that.

But we're going to get a good spread of tests on that acreage by year-end and that's an appropriate level of interest considering how we valued this acreage when we got into it.

Understood.

So the inventory in Howard mostly based on 660-foot spacing.

What testing are you going to do on the downspacing this year?

I guess how tight will you test, and is it going to be mostly in areas that are currently de-risked?

Yes.

Chris, let me just say that on the spacing side, where the sections, like in Wolfcamp A, are quite thick, we stagger them, right.

So the spacing, on a plan view, could look really tight.

And then within an individual (inaudible), they'd be wider.

But we're not really sharing what our plans are there.

Obviously, that's one of the key competitive differences, especially when you're out there on a leasing program.

But we test those and we look at how they're doing.

And then we modify the design accordingly.

But we're not elaborating on which ones are what spacing probably because the thicknesses vary and how much staggering we're doing in our wells.

Okay.

And I believe last quarter, you were testing 400-foot spacing over at Sweetie Peck.

Is the inventory updated for that tighter spacing at this point over there?

Yes.

So for the Rock Ridge in that economic inventory or the RockStar acreage, it all assumes simply the eight per section.

In Sweetie Peck, we've got eight per section in the Wolfcamp A. And then we've got ten to 12 and not everywhere but in certain areas in Wolfcamp B and Lower Spraberry.

So that's the sort of level we've gone to so far.

We see potential to do even more, but we're going to take it step by step.

And we're bringing all our tools to bear here too.

So we used reservoir simulation.

We used rate transient analysis to assess our completions.

And then we do quite a bit of statistical analysis also.

So yes, Sweetie Peck's further along obviously than RockStar since we just got the asset.

All right and maybe I'll just try to slip one more in here.

When we look at the 2019 guidance, you guys dropped down to ten Permian rigs from 11 and you go to two in the Eagle Ford.

What's driving that sort of dynamic there?

And do you build DUCs in the Permian in 2019 while working down your Eagle Ford DUCs to achieve that Eagle Ford growth?

That's probably a little bit too granular.

I'll let Herb jump in.

This is Wade.

But I'd point you to one of my (inaudible).

It really could vary.

The numbers are going to be driven more by number of wells completed obviously.

And there will be -- I'm confident -- efficiencies gained from here to there.

So it's kind of playing with the rigs and it can be a little confusing.

But Herb?

Yes.

And Wade got it right on.

Basically, we know when we prosecute a drilling program that we get much more efficient and the spud-to-spud timings drop from where we are earlier.

So when we put the 11 rig count out there, that had certain assumptions.

And we know we're already drilling faster.

We just actually drilled a well, believe it or not, 7,500-foot lateral in 9.7 days.

That broke all the records for us.

Now, we won't do to that on every well.

But when you get that kind of performance, you obviously get a lot more wells per rig.

And you can expect to see that over time.

Yes.

It's a shame in a way to show rig count because really the focus ought to be on completion count because rig count is going to -- I think it'll go down actually over time as we drill faster, so.

Yes, thank you.

Thank you.

And our next question comes from the line of Jeff Robertson with Barclays.

Your line is now open.

Thank you.

A question on reserves.

I don't know if this is for Jay or Herb.

But you all, it looks like, added 44 million Boe of undeveloped reserves in the Eagle Ford at the year-end and about 8 million Boe in the Wolfcamp and Spraberry.

Can you just talk about -- I assume the Eagle Ford reserves were added in the eastern portion that you were describing with the spacing results.

And then in the Permian, can you talk about where those came from and how much of that is at Sweetie Peck versus the new asset?

Okay.

Yes, I can try and summarize that for you.

So you're aware how the proved reserves work and with the (inaudible) rules and really just doing a one-well offset to existing wells.

So in the RockStar area, we obviously bought some proved reserves.

And then we had a limited ability to add on because it's basically just new wells that you can add on or PDP wells that you can add on, additional proved reserves.

So a limited amount there.

So, yes, most of the Permian is Sweetie Peck.

In the Eagle Ford, it's the same sort of story where you're doing offsets.

But we've got a lot more wells there.

So we have the ability to really upgrade on performance of wells and then also add in the wells we've drilled and some of the offsets to those.

So the distribution of 2016, it's really that Pilot 7 area where we had 24 completions out of 45 completions in the total Eagle Ford.

And then I showed some of where the other ones are on the east side.

I don't have it on the top of my head what percentage are east versus west.

But you know the Pilot 7 wells were 24.

That's probably about what we had on (inaudible).

Yes.

I think the key of this message here is that on the RockStar acreage that we just bought, we're not at a point yet where we can book a whole bunch of wells over a wide area based on a reasonable certainty.

We're still booking on single offsets.

We don't have that many wells.

And now as we get forward into the future, we're going to be able to start booking these based on our own activity and other people's activity.

We'll be able to book larger areas of PUDs.

So you'll see PUD percentage there going up a lot.

And obviously, given the production growth and the wells we'll be drilling, you should see massive reserve growth in the Permian over the next few years.

Okay.

Thanks, Jay.

You bet.

Thank you.

And I'm showing no further questions at this time.

I would now like to turn the call back to Mr. Jay Ottoson, Chief Executive Officer, for any closing remarks.

Well, I just want to thank you all for your questions today.

We look forward to sharing our progress with you through the rest of the year.

Thanks again for being on the call.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude the program and you may all disconnect.

Everyone have a great day.