Diamondback Energy Inc (FANG) 2018 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter 2018 Earnings Conference Call.

As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Adam Lawlis, Director, Investor Relations.

Sir, you may begin.

Thank you, Amanda.

Good morning, and welcome to Diamondback Energy's First Quarter 2018 Conference Call.

During our call today, we will reference an updated investor presentation, which can be found on our website.

Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; and Tracy Dick, CFO.

During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses.

We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors.

Information concerning these factors can be found on the company's filings with the SEC.

In addition, we will make reference to certain non-GAAP measures.

The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I'll now turn the call over to Travis Stice.

Thank you, Adam.

Welcome, everyone, and thank you for listening to Diamondback's First Quarter 2018 Conference Call.

The first quarter was a strong start to the year for Diamondback as we grew production 10% quarter-over-quarter and delivered a company-record realized cash margin of 83%.

Our low-cost operations and capital-efficient production growth enabled us to generate $21 million in free cash flow for the quarter while earning over a 13% annualized return on average capital employed.

We are operating 11 rigs today: 6 in the Midland Basin and 5 in the Southern Delaware Basin, along with 5 dedicated completion crews.

As we look ahead to the rest of 2018, we will continue to match operating cash flow to drilling and infrastructure CapEx and increase or decrease rig count accordingly, as we have done now for over 3 years.

We continue to see improving well results across our acreage with standout long-dated production from multiple wells in Pecos County as well as a unique test of the Third Bone Spring shale in Reeves County.

Leverage remains low at 1.2x annualized EBITDA, and we are set to pay our first quarterly dividend on May 29 to shareholders of record on May 21.

Moving forward to Slide 6. We give an update to our takeaway strategy.

We currently have over 90% of our total production on pipe moving to 95% or higher by year-end 2018, removing the risk of rising trucking cost from our forward operating plan.

We have multiyear acreage dedication and firm service for in-basin gathering on the Oryx, NuStar and Reliance systems, which deliver barrels to the Crane, Midland or Colorado City markets.

These systems then have multiple downstream connection agreements in place to long haul pipelines.

We sell our barrels at the wellhead to multiple first purchasers throughout the Permian, who have physical space on various long-haul pipelines out of the basin.

On top of this, as part of our long-term strategy to maximize international pricing exposure, we recently signed a 50,000-barrel per day agreement to be a firm shipper on the Gray Oak pipeline and are actively working multiple firm purchasing deals to maximize pricing exposure over both the near term and the long term.

Because of the attractive nature of the Gray Oak project, we've been able to leverage our substantial multiyear firm commitment of 50,000 barrels delivered to the Gulf Coast in exchange for near-term flow assurance in Gulf Coast pricing solutions.

We look forward to continuing to update our shareholders as these initiatives progress and believe the only way to guarantee flow assurance out of the basin is through firm space and through take-or-pay contracts versus financial protection.

We soon expect to have a majority of our barrels exposed to an international price.

Turning to Slide 7. We demonstrate not only our acquisition track record but also the subsequent deal-by-deal per share value created as a result of this acquisition strategy.

Since going public, Diamondback has grown EBITDA per share by over 700%, while commodity prices have declined 28% over the same period.

We have been active yet selective in our acquisition strategy, with accretion and full cycle economics serving as the primary drivers of our decision-making process.

As shown on Slides 8 and 9, Diamondback's acreage quality, low capital costs and low cash operating costs allow us to have a peer leading recycle ratio and therefore, grow production faster per dollar of CapEx without compromising our balance sheet.

We consider ourselves fundamental investors and continually work to grow EBITDA per share and generate true earnings per share growth in an industry not known for EPS growth, especially through a commodity downturn.

Looking forward, we will continue to value fundamentals to drive long-term shareholder value.

With these comments now complete, I'll turn the call over to Mike.

Thank you, Travis.

Diamondback has had another great quarter.

I would like to take this opportunity to thank all of the effort and hard work that all of the Diamondback employees continue to exhibit.

It is through their tireless pursuit for excellence and focus on detail that we have been able to outperform expectations quarter-over-quarter.

Turning to Slide 11.

During the first quarter, Diamondback generated $21 million of free cash flow and has maintained capital discipline by growing production 67% over the last 5 quarters while generating $90 million of EBITDA in excess of our CapEx over the same period.

Diamondback plans to maintain this level of capital discipline in the coming years by continuing to add rigs only as cash flow allows.

Turning ahead to Slide 13.

We continue to be industry leaders in terms of both cash cost and cash margins, with the first quarter representing a company record in terms of realized cash margin at over 83%.

Our investments in infrastructure, especially in the Delaware Basin over the last 24 months, have enabled us to increase realizations and decrease LOE sooner than originally expected.

Slides 15 through 18 give more detail on our Delaware Basin operations, infrastructure investments and continued improving well results.

Since the acquisitions we made in 2016, we've increased our average working interest by over 10% on these properties and added over 5,000 net acres of credit to our outstanding land team.

We had new data from multiple well results across these assets, including 3 90-day IPs that demonstrate the strong extended performance of the wells in the area.

We also announced the successful test of an emerging new zone in Reeves County, the Third Bone Spring shale.

As seen on Slides 16 and 17, we have the majority of all oil and gas as well as fresh and saltwater on pipe across both of these positions, and full field electrification will lower our ESP power generation cost by $60,000 per well per month when in place throughout the second half of 2018.

As I mentioned before, the infrastructure investments we have made across these acreage positions are beginning to show benefits via higher realizations and lower LOE.

Turning to the Midland Basin on Slide 19.

We're currently running 6 rigs and 3 completion crews.

Two of these crews are currently using local sand.

This will result in savings of $60 per foot versus current first quarter cost.

We expect to use local sand for all Midland Basin completions beginning this summer.

Also on Slide 19, we discuss our continued shift to larger pads and multi-zone development across the Midland Basin, having recently completed our second 8-well pad in Spanish Trail and flowing back our first 7-well pad in Glasscock County.

With these comments now complete, I'll turn the call over to Tracy

Thank you, Mike.

Diamondback's first quarter 2018 net income was $1.65 per diluted share, and our net income adjusted for noncash derivatives and other items was $1.64 per share.

Our adjusted EBITDA for the quarter was $341 million, up 13% quarter-over-quarter, with cash operating cost at $8.42 per BOE.

During the quarter, Diamondback spent $275 million on drilling, completion and nonoperated properties and $43 million on infrastructure and midstream investments.

For the quarter, we generated $21 million of free cash flow, excluding acquisitions, and have now cash flow at the business in aggregate to the past 13 quarters.

As shown on Slide 21, Diamondback ended the first quarter of 2018 with a net debt to Q1 annualized adjusted EBITDA ratio of 1.2x and roughly $800 million of liquidity.

In connection with our spring redetermination expected to close later this month, the lead bank of Diamondback's credit facility recommended a borrowing base increase to $2 billion from $1.8 billion, while we intend to limit the lenders' aggregate commitment to $1 billion.

We raised the bottom end of our full year 2018 production guidance to 110,000 BOE a day, with the top end remaining unchanged at 116,000 BOE per day.

The midpoint of our updated production guidance now implies 43% year-over-year growth.

Finally, Diamondback's Board of Directors have declared a cash dividend for the first quarter of $0.125 per common share payable on May 29, 2018, to shareholders of record at the close of business on May 21, 2018.

I'll now turn the call back over to Travis.

Thank you, Tracy.

Diamondback was able to deliver another great quarter as a result of our continued commitment to execution and low-cost operations.

We're increasing production guidance while maintaining capital spend and lowering cash operating cost for the year.

Diamondback will remain proactive in all aspects of our business, including leveraging our size and scale, to secure smart marketing agreements that position us well for both the near and long term.

Operator, please open the line for questions.

(Operator Instructions) Our first question comes from Neal Dingmann from SunTrust.

Travis, the question I have is looking at Slide 14, where you show sort of your balance inventory.

Given that great result you had in that Third Bone in Reeves, any thoughts on just space?

I'm looking particularly at the space in there.

You guys are still pretty conservative.

I know that's always been management style.

But I'm just wondering, do you see more upside after seeing the size of that recent well?

Yes.

Certainly, we're encouraged about that.

That's -- most of the commentary you've heard out of that portion of the basin has been from the Third Bone Spring sand, and this is really the first that we tested the shale and has really good results.

We didn't count that as any kind of inventory at acquisition time, and we don't include it as inventory in our go-forward plan either.

So certainly, good well results like this lend us to be more aggressive at future development.

But right now, we're just going to continue to gather data on it.

But yes, we're excited about it, and it has positive ramifications for our inventory long term.

Okay.

And then just one follow-up for you or Kaes.

Just on that comment you mentioned about the majority.

Going forward, you suspect that the majority of your production could be exposed to international market.

I mean, any other color you can give on how you might accomplish that?

Yes, Neal.

The (inaudible) deal is the first of many we're looking to take to, over the long term, expose all of our barrels to the international market.

I think getting our barrels on a ship will get us a global price and remove the differential risks that we've seen rear its ugly head here in the last 3 months.

So this is the first step of many, and we look forward to announcing multiple other deals over the coming quarters as we look to diversify away from the Midland market.

Our next question comes from the line of Dave Kistler with Simmons Piper Jaffray.

Specifically looking at your Slide 6 here and the comment that 50% of the production is firm in '18 in terms of, I guess, firm transport.

And then in '19, 45,000 barrels are firm.

Can you give us some details or a little bit more color around exactly what those contracts look like and the destination for that crude?

Yes, David.

These are all Midland Basin prices.

I think the term firm has been thrown around a lot lately.

We have access via all the in-basin pipelines to get our barrels where they need to go and have deals in place for all barrels for third-party marketers to market downstream.

In this case, these contracts are a little stronger than your traditional term sales agreement.

It's a firm sales agreement.

And what we're trying to do here is these are exposed to the Midland market, but we will be adding deals that are exposed to other markets over the near and long term.

Okay.

And not to press too hard on something you probably can't share too much details on, but any color you could share.

You mentioned the ability to maybe use the Gray Oak contract -- or leverage the Gray Oak contract to secure near-term capacity.

Just trying to understand, would you be looking at swapping out some of the firm commitment you've put in place there?

Or through the relationship with the folks at Gray Oak, does that help you secure potential available capacity that, in your words, is term versus firm from some folks potentially?

Yes, I'll put it a little differently.

Diamondback, we're not a marketing company.

But we did -- what we did with the Gray Oak Pipeline is we're essentially taking our barrels one step further.

So at the end of the day, those barrels need to be marketed by one of the larger international marketing firms that we have great relationships with and have been doing business with throughout the last 6 years as a public company.

So that 50,000 barrel a day commitment is a very enticing, sizable commitment for someone to market over the next multiple years after we make that commitment.

So in exchange for that, we might pay up for secured firm transport in the near term.

But I'm looking to exchange that for someone to come in and market those barrels long term for us.

Okay, great.

If I can sneak one last one in here.

Given what's happened with mid-cush diffs, does that potentially change sort of the dynamics of the acquisition market as we look at some people who might be suffering from compression of price realization and maybe free up some incremental or differentiated assets that you guys would be interested over time?

I'm just curious how you think this shapes the acquisition market.

Certainly, Dave, as it continues to evolve, we take all that into our acquisition model as we price future cash flows, and then discount them forward.

So yes, it could, but we're just going to be continuing to use our disciplined approach on acquisitions.

And we'll evaluate all the deals what the current market conditions are, and we'll respond accordingly as we look for accretion in these deals.

And just -- Dave, just on the acquisitions.

Diamondback, currently, we're not more interested or less interested in acquisitions than we've ever been in our company's history.

M&A activity is as fundamental to Diamondback Energy as the air that we breathe.

It's something that we've done from day 1, and we're going to continue to demonstrate that discipline in looking for accretion and looking for ways that we can deliver differential results to our shareholders.

That's one of the reasons that we put that slide in there on Page 7, is to say we've got a good track record of doing smart deals for our shareholders.

And so we're just -- that's the way we always behaved, Dave.

Our next question comes from the line of Bob Morris with Citi.

Travis, when you laid out the full year budget, you assume in that budget around 12% year-over-year cost inflation in Midland and about 17% in the Delaware Basin.

Is that what you still expect?

Or given the discipline amongst your peers also out there, do you think that inflation is likely to come in lower than that at this point as you look forward?

I think we're going to continue to see, Bob, the cost increases over time as activity level continues to go forward.

So I can't speak for what our peers are going to do, but I can say that we continue to be disciplined on how we allocate capital dollars, and we're not a big proponent of the kind of the drill baby drill mentality and outspending cash flow.

So I can just tell you how Diamondback is going to perform, and I think we've got a good handle on what we think service costs are going to do over the next couple of quarters.

So you would still stick to that 12% to 17% inflation expectation here as you look to add rigs going through the year?

That would still be part of your budget or you still think that's accurate?

Yes.

Bob, I think it's too early to change that based on what we've seen so far this year.

The one benefit we do have is we were one of the first E&P operators to sign up for a local sand deal, and we're getting a lot more local sand than we expected earlier in the year.

So that should save $60 a foot for our Midland Basin well costs.

And by midyear, all of our Midland Basin wells will be using local sand, saving about $60 a foot versus our current well cost.

Yes.

That's been a great move by you, guys, and a big positive.

My second question is just as you look to match activity with cash flow, how quickly can you add rigs and completion crews?

Is it just physically one rig and maybe a crew every quarter?

Or how quickly -- if cash flow continues -- free cash flow continues to ramp up, how quickly can you ramp activity?

Yes, Bob.

We did our budget at $55 a barrel at the beginning of the year, and we anticipate it at that pricing even with differentials at $3 or $4 at the beginning of the year, that we could add a rig every 4 or 5 months.

And I think we're probably speaking to that type time frame.

We added rig 11 in Q1, and I'd anticipate rig 12 on its way some time midsummer.

Our next question comes from the line of Gail Nicholson with KLR Group.

Looking at kind of the working interest adjustment in the Delaware since the announcement of the acquisition, you're up 10%.

How do you just kind of see that landscape going further?

Do you think there's more room for trades in (inaudible) the Delaware?

Or do you kind of feel like where you sit, an 82% working interest is a good kind of run rate to use?

Gail, that's a good question.

But I'll tell you that that's a fundamental part of each of the asset teams in the area.

They do that day in and day out.

And the expectation is that they can -- are their own little business development teams, and they continue to look for ways that creatively can add swap acreage or purchase small bolt-on deals.

Again, it's just as fundamental as a part of our business as taking leases and drilling wells.

And then with the nice initial result in the Third Bone Spring share potentially being inventory out of the Delaware, some of your peers in the Midland have been -- had some good Jo Mill results in and around your acreage.

Kind of (inaudible) other potential zones over in the Midland?

We're looking -- this is Paul Molnar.

We're also looking at the Middle Spraberry shale, Jo Mill.

We focused on the highest rate of return projects in each area.

But we are testing other zones ourselves.

And also, we're monitoring the results of our offset operators' drilling.

So we anticipate additional inventory as these zones get proven up.

Yes.

Gail, again, we've always been known as a fast follower, and we intend to be fast followers as we see other zones derisk.

And then just one more on the locally sourced sand.

I know that's the -- where you're moving towards Midland, and you previously said that you were not willing to test it in the Delaware at this point in time.

There has been some operators utilizing that locally sourced sand in and around your area.

Any revised thought from the use of locally sourced sand over in the Delaware?

Yes, Gail.

We actually use some 100 mesh locally sourced over the Delaware as well as we're looking for a test this quarter who will test some local sand in the Wolfcamp A in the Pecos County area.

The next question comes from the line of Jeff Grampp with Northland Capital.

I was curious to get your thoughts on general, I guess, average pad sizes for you guys.

It seems like you're incrementally kind of moving up doing some 7- and 8-well pads.

And as you guys continue to grow and add to activity, you mentioned 12th rig by midsummer, how do you guys kind of think about average pad size potentially changing going forward?

Yes.

I think the testing that the asset teams continue to do with bigger and bigger pad sizes will probably move more towards that 4- to 8-well pad development.

If we're doing 2 zones, 2 zones and can kind of do the wine rack staggering on as you go forward.

Okay, great.

And then on the cost side, you guys reduced your unit LOE.

Can you talk a little bit about any particular drivers in that?

Is that maybe some of these infrastructure projects in the Delaware coming on later this year?

I guess, is there anything noteworthy that might be driving those costs to go up?

Sure, Jeff.

The infrastructure projects are the biggest drivers.

Over in the Delaware Basin, getting all of our fluids on pipe are really helping us to reduce the LOE cost as well as realizations.

What we're also seeing, of course, is production growth helping on the denominator of that equation.

But going forward, the electrification that's about to happen over in the Delaware for us is going to be a big driver and gives us the confidence to lower our LOE guide for the rest of the year.

Okay.

And if I can sneak one more on the realization side in the Delaware.

Do you guys have maybe a rough split on how your oil production is weighted between Midland and Delaware just to, I guess, get a better sense of, on a corporate level, how your realizations might change?

About 3/4 Midland, 1/4 Delaware at this time.

The Delaware is going to continue to pick up steam as we now have 5 rigs running there full time.

Our next question comes from the line of Mike Kelly with Seaport Global.

Guys, I wanted to just go back to the marketing side of things here and make sure I'm looking at this the right way.

So today, it looks like you don't have any barrels that are getting international pricing.

But in your comments here, it sounds like you'll soon have the majority of your near-term barrels exposed to international pricing, if I heard that right.

It's a -- I think my question on this is just, one, on the timing, when should we kind of feather these barrels in for international pricing?

Just get a sense of that.

And then, obviously, I mean, you're taking a $13 hit on Midland pricing today.

Getting international pricing can be very attractive.

I'd imagine you're going to have to pay a decent cost to make that happen.

Just kind of wanted to get a sense on how you should think about that transport cost in order to make that arrangement feasible.

Yes, Mike.

It's tough for me to comment on deals in progress, but I can assure you there are multiple deals we are working to increase the international pricing exposure, granted you will have to pay up for it.

I think it'll be somewhere between where the Midland market is today and international market is today.

But obviously, can't comment.

But the one thing I can share is that the attractiveness of our 50,000 barrel a day commitment among other commitments we're looking to make do allow us to talk -- use our scale and talk about an interim solution, granted it's going to be a more expensive solution, just less expensive than the cash market we're seeing today.

And what do you think if we look out to maybe like Q4 this year, what's ideal for you?

How much of your crude is exposed to Midland pricing versus more international?

Yes, Mike.

As we get some more clarity around all those, we'll be very fulsome in our disclosure.

Just not prudent to speculate on deals in progress right now.

Yes, fair enough.

And Travis, one for you.

I mean, we've got 2 press releases out from you guys now just stressing the discipline on the M&A front.

And we'd just like to hear maybe a little more insight into your acquisition model and maybe some of the core tenets of that disciplined approach.

Yes.

Those core tenets have never really changed.

Specifically, the acquisition has to compete for capital immediately.

We're not going to buy something and then park it in inventory.

It has to be accretive on the measures that we care about.

And it needs to be complementary to our existing asset base and some of the other things that we manage around here with our infrastructure and our mineral business.

So it's not particularly complicated, but it's a -- there's a lot of brilliance in the simplicity of just doing accretive deals that are smart for our shareholders.

Our next question comes from the line of Charles Meade with Johnson Rice.

I wanted to go back to that [Roger 6] unit well, the Third Bone Spring shale.

And I want a just a brief commentary.

That shale versus sand subtlety may be lost on some of the investment community.

But anyway, I wanted to ask if you could kind of give a narrative on how the case to drill that well and land that well where you did, how that case came together.

And if what you've seen in the early days from this well has you now looking perhaps further up the column in the Delaware in the first and second Bone Spring sections.

Yes.

I'll let Paul answer the -- on the geoscience about the decision to land that.

But I'll tell you, we're very judicious in how we move away from the highest rate of return zones.

And we -- I think it's reasonable to expect that the vast majority of our future development in the Delaware is going to remain in the Wolfcamp A interval.

But Paul, on the decision to land it in the shale interval?

All right.

That was based on a combination of core data and petrophysical log data.

There were a few other operators in the general area about the same time, look like they had the same idea.

There's been a few other tests that also seem to have pretty good results in the zone.

We know the Bone Spring sand -- Third Bone Spring sand is prolific to the northwest of us.

The thing we wanted to avoid was drilling that first before you drill the Wolfcamp A because the Wolfcamp A is overpressured and there could be issues with developing the Wolfcamp A after the Third Bone shale.

You want -- or Third Bone sand.

You want to drill the Wolfcamp A either first or codevelop the 2 zones.

We wanted to test the Third Bone shale.

It's equivalent actually to the Lower Spraberry shale in the Midland Basin.

And again, we're very pleased with the results.

But yes, we have additional information at future tests in some of the shallower Bone Spring zones.

As you mentioned, the first and second maybe succumbing somewhere down the line.

Okay.

And then perhaps there was -- I think there was some talk that you guys were looking to perhaps farm out some of your more Southern Pecos acreage to maybe promote in a partner.

Is there any update on that?

Or maybe have any of these recent good Wolfcamp wells in Pecos County changed your appetite there?

Charles, can't comment on processes in place.

I will say a few things about that process as some acreage on our southeast portion of our Pecos County lock.

And we're looking for a partner to help us develop and bring some value forward as that acreage kind of shifts in the lower quartile of our inventory.

I think it also provides a benefit to our midstream business as well as our minerals business.

Our next question comes from the line of Jason Wangler with Imperial Capital.

I just had one.

Your thoughts as I think you guys have spoken on with Viper as well looking at a drop-down at some point.

Assuming you guys would get cash from that type of transaction, where would you look to deploy that given you guys are running at free cash flow and don't really have any debt needs?

Just kind of the thought process on use of proceeds as something that's come to transpire.

That's a good conversation that we're looking to have.

Traditionally, that extra cash would primarily go to debt reduction on a revolver.

And then on top of that potential acceleration, which will then benefit the Viper minerals and the parent company.

Okay.

And then Kaes, just kind of delve on the last question, it sounds like, I guess, Viper may have some of the minerals sitting under that acreage that you're looking to farm out from the Diamondback side.

Is that right?

It's safe to assume that Viper is looking to acquire under -- everywhere Diamondback has acreage.

Our next question comes from the line of Richard Tullis with Capital One Securities.

Two quick questions for you.

You spoke a little earlier about it's too early at this point to look at potentially changing the cost expectations for 2018 wells currently have budgeted 12% to 17% cost inflation.

Can you talk a little bit about what's been the inflation experience to date in your AFEs?

Richard, we're in that 5% to 7% range today.

Rigs and a few other things are moving.

We're seeing a little bit of tightness.

We also have some things happening throughout the year, the sand getting utilized against all 3 of our frackers on the Midland side.

We're beginning to help that as well.

There's a few things out in the future that we're looking at as far as steel tariffs and some other things that we don't have full clarity on.

So to go and change our estimate today is a little premature.

But we did take into account that we would have it basically Jan 1 through the whole year.

That hasn't been the case to date.

But again, we still have a lot of time left in the year.

Yes.

Richard, just to add to that, you know Diamondback's philosophy on cost increases.

We're not willing to give back any ground, and so we're continuing to push the efficiency envelope everywhere we can.

And the expectation is that we always offset cost increases with improved efficiencies.

That is not always practical, but that's still our basic operating philosophy.

That's helpful, Travis.

And just lastly, you had a nice uptick in cash margin for the first quarter.

Can you talk a little bit about what your margins have been to date in this quarter?

Just how comfortable are you in being able to maintain that sort of cash margin level that you saw in the first quarter?

I think we feel very good about the cost side and the unit cost as oil price continues to increase and realizations increase.

That margin should stay steady to increase.

The only variable cost in that margin is -- are the taxes we have to pay on the crude, and that's based on a percentage of realized price.

(Operator Instructions) Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

I guess just wanted to hit on a few things.

First, on the acceleration case, you've talked through of adding the 12th rig later this year.

I'm just curious how you think about that in the context of the infrastructure constraints that the industry is facing in 2019, assuming that most of the uptick in activity later this year would impact 2019.

How do you kind of balance those 2 things when in a normal world, you would accelerate into the higher price environment, but in this current scenario, certain headwinds are obviously in place for 2019?

Michael, just like on my commentary on acquisitions, we evaluate all the cards face up on the table when we make these decisions.

And if you've got midstream issues that are compounding the economics to our -- economic returns to our investors, we'll respond accordingly.

It's up to us to, like we talked about, to fix those things and anticipate we'll be doing that and be talking to you guys about it in the not-too-distant future.

Okay.

And I guess, then related to that, is there a Midland price discount that on its own would reduce your activity?

Or is it really just -- what's the overall corporate cash flow and then aligned activity to that?

(inaudible)

Yes.

If you don't mind, I'm not going to speculate on exact price point in which Diamondback is going to change behaviors.

I think you can look at the way that we've historically managed the company and the balance sheet, and we've done so in a very conservative way.

And just like I've always said, when returns to our investors go up, we accelerate into that environment.

And just like we've demonstrated in the past, if returns go down, well, we pull back activity.

So just more to come on that, Michael.

We'll see.

We'll see.

I'm anticipating the organization is going to -- will have plenty of solutions, so just more to come.

Yes, makes sense.

It seems like you've provided some good signals to us today anyways.

And then I guess, lastly -- sorry, go ahead.

Michael, I'm just going to add to that.

I mean, if you look at what our -- this -- we've (inaudible) the highest percentage of cash operating -- cash margins this quarter.

Our cash flow is at an all-time high.

So we're really in great financial shape.

We've cash flowed the company now in aggregate for 13 quarters in a row.

So I mean, we've got a lot of really positive things happening on the financial side of our business as well.

I'll add 2 things to that.

Looking at 2016 -- sorry, 2017, we grew production 85% year-over-year within cash flow at below $50 crude for the year.

And we ran our budget this year at $55 crude less $3 dips and said we're going to grow 40% within cash flow to $1.4 billion budget.

So I think we feel very comfortable about those numbers with WTI at $70 today.

Okay, very clear.

Appreciate it.

One last little one on my end.

Can you just clarify the differences between term and firm as you think about it and describe it in the deck?

Just want to make sure we're all thinking about that right.

My opinion of a firm deal is a true take-or-pay deal.

We have -- if you don't use it, you pay.

A term deal is -- are deals that you can flow crude and you have a deal with someone.

But I think a firm deal supersedes a term deal in the so-called oil capital structure.

And in the term case, I guess, what assurance do you have that the buyer will take those barrels?

Is that the primary difference, I guess, between the 2?

That would be my opinion.

At this time, I would like to turn the call back over to Travis Stice, CEO.

Thanks again to everyone for participating in today's call.

If you've got any questions, please contact us using the contact information provided.

Ladies and gentlemen, that concludes today's call.

Thank you for your participation.

You may now disconnect.

Everyone, have a great day.