Diamondback Energy Inc (FANG) — Q1 2019 Earnings Call Transcript

Thank you, Sidney. Good morning, and welcome to Diamondback Energy's First Quarter 2019 Conference Call. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, President and COO; and Kaes Van’t Hof, 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 in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. 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 2019 Conference Call. After closing the Energen acquisition in the fourth quarter of 2018, we ensured that Diamondback got off to a fast start in 2019 and showcased the strength of our operations organization and the low-cost structure on a larger scale. We navigated the $30 drop in fourth quarter oil prices by immediately cutting activity to start 2019 while still growing production 5% from our December 2018 exit rate of 250,000 barrels a day, all while integrating our $9 billion acquisition of Energen and the addition of over 300 employees to the Diamondback family. I'm going to pause and take a minute to give credit to all of the employees within Diamondback for working together with the new, significantly larger group of colleagues and executing on this plan seamlessly. Both the Diamondback and former Energen employees have learned best practices from each other, and the results have shown through in the capital and operating costs presented in our first full quarter as a combined company. Our first quarter results and revised expectations for capital cost reflect the execution of the synergies presented in the merger presentation with Energen last August. Diamondback is on pace to achieve our previously disclosed synergy targets earlier than expected, and we will continue to push efficiency and drive down cash operating costs. Diamondback spent $627 million on CapEx in the first quarter and generated $675 million of EBITDA with $8 per barrel cash operating costs, including $0.55 per barrel G&A. We completed 82 wells in the quarter and are maintaining our expectations to bring on between 290 and 320 wells this year from a $2.7 billion to $3 billion capital budget. Capital discipline is important to Diamondback, and we have no intention to exceed this budget or well count in 2019 regardless of commodity price. From a Corporate Development perspective, we executed on our grow and prune strategy by signing definitive agreements to divest the conventional assets acquired from Energen as well as noncore acreage in Crockett and Reagan counties. These transactions are expected to close by July 1, and as a result, we have lowered our full year production guidance to account for the production expected to be lost from these properties in the back half of the year. We also lowered our full year LOE guidance by $0.25 a barrel to account for the higher operating cost structure of these assets. Secondly, we also contributed the oil gathering and saltwater disposal assets acquired in the Energen acquisition into our midstream subsidiary, Rattler Midstream, with market-based contracts in place. Lastly, we are actively working on dropping down the remaining mineral and royalty assets held at the Diamondback level to Viper and expect to do so at some point in 2019. Most important in this quarter, our Board of Directors has authorized up to a $2 billion capital return program to be executed in the form of a stock repurchase program by the end of year 2020. This program is a direct reflection of the confidence we have in our business plan and free cash flow outlook given the improvement in commodity prices from the original 2019 budgeting process, our capital budget control, and the expected improvement in our oil realizations as legacy fixed differential contracts have rolled off and we move more of our barrels to the Gulf Coast. With this announcement, we have set a clear use of proceeds for this free cash flow and expect to generate over $750 million of free cash flow from operations in 2020 at $55 WTI. Over the long term, the consistent growth of our dividend will remain our primary return of capital objective, but this repurchase program represents the next step in our total return strategy and the evolution into a large-cap commended pure-play. At a high level, our capital allocation philosophy is grounded on achieving pure leading year-over-year growth, supporting a growing dividend, reducing debt consistently, and continuing to replace and maintain a deep inventory at Tier 1 acreage. Excess free cash flow above this will be returned to stockholders. Diamondback will not spend every dollar of free cash flow on growth or acquisitions. Put simply, we feel buying back our stock is the best acquisition opportunity we see today given our outlook and the multiple visible catalysts ahead. With these comments now complete, operator, please open the line for questions.

Travis, please address the key point you mentioned regarding the significant stock buyback announcement. Can you discuss your expectations for future production growth in the coming years if you continue this buyback strategy? Essentially, I'm asking if you still anticipate growth to remain around the 26% target level you've outlined today, particularly in light of this substantial initiative to return value to shareholders.

We are not in a position to provide long-term guidance on our growth rate. However, if you consider our growth rate from last year, which was between 40% and 50%, this year it stands at approximately 26%. The reality of larger numbers will eventually impact us. We expect to continue growing in the coming years, and the focus remains on growth. We will maintain a practice of spending less than we earn and consistently returning capital to shareholders as part of our overall return strategy.

Could you share more about your capital budget? Specifically, I'm curious if it includes acreage acquisitions, equity investments, and the VNOM acquisition. I believe you're around $300 billion in the first quarter. Is that a solid run rate? I'm trying to understand it in relation to generating cash flow, particularly regarding stock buybacks.

Yes. Neal, I'll take that one. Yes, I mean the capital budget, $2.7 billion to $3 billion, is for drilling and completion, midstream and infrastructure. On top of that, we have our equity investments in the Gray Oak and the EPIC pipelines, which are going to be held in our Rattler subsidiary. And we really don't consider one-time proceeds, whether that's asset sales or asset purchases, in that budget. So really, the key message is free cash flow is going to be operating cash flow less the CapEx budget and the dividend that we plan to grow continuously.

So Kaes, is that cash flow that you'll use to buy back the stock, you won't do that with debt or something?

No. No plans.

Following up on the plan to return cash to investors, can you just talk a little bit about the priorities of paying down the revolver versus share repurchase? And then how are you expecting to time the share repurchase portion relative to expected versus actual free cash flow and expected versus actual asset sales and monetization proceeds?

Sure, Brian. We've committed to reducing our debt. I think our debt leverage ratio is around 1.9, and we'll probably get that reduced here pretty quickly. Kaes, do you want to answer the back part of that?

Yes. The revolver right now is $1.9 billion, Brian. We're going to get that down by $700 million or $800 million with one-time proceeds on the free cash flow piece. It's really what we see in the model in Q2 through Q4 of this year and then 2020 at nearly any commodity price, let alone strip. The majority of that free cash flow is going to go back to shareholders in the form of this buyback.

Great. And then shifting to the assets in the broader consolidation landscape, you've never been shy to participate in consolidation. You talked about the grow and prune strategy. Can you just talk about the landscape that you see out there, both in terms of further pruning asset transactions like what you announced here with the noncore asset sale, bolt-on acquisitions to further that scale, and then the potential for larger-scale M&A?

We have clearly stated that pursuing small acquisitions, or bolt-ons, leveraging Diamondback's operational strengths, is part of our fundamental strategy, so we will continue to engage in those. As responsible capital allocators, it's crucial to consistently evaluate our portfolio and assess whether late-life assets are more beneficial in our hands or would be better off with someone else. Recently, we sold $322 million worth of late-life or low-value assets. Regarding larger deals, I won’t speculate on those opportunities. My primary responsibility is to create value for our shareholders, and we believe that right now, this is best achieved through excellent execution, cost-effective operations, and fulfilling the commitments we just outlined. I can’t comment on industry M&A trends; my focus is on what I can control and ensuring that we drive shareholder value.

Congrats on your strong update decision to pursue a meaningful share repurchase.

Thank you, Derrick.

For Travis, this is an open-ended question for you on a related topic to Brian's last question. As you guys know, M&A has been a topic of increasing interest among investors. Based on really your success and the progression you've made from midcap to bellwether status, could you share with us your views on the merits of zero premium mergers among your former midcap peers to create advantaged pro forma companies and the scale and overhead synergies that come along with that? And I think to some degree, we all live in spreadsheets, but I imagine the execution is quite a bit harder than perceived.

Yes. Certainly, execution is a lot harder than just the spreadsheet. And I think we learned that in our early days. But again, Derrick, I just want to focus on what I know, which is my job is to represent what Diamondback does and control these best-in-class operations and really pristine execution. And really, all I know about what's going on in the larger space is what I read in the press, and I don't want to be the industry spokesman talking about what goes on in the M&A world. I'm really focused on what message I can deliver to the shareholders that own Diamondback. And that's what we're trying to accomplish.

Completely, sir. And then as my follow-up, perhaps for Mike. I mentioned this to you guys last night, but your track record in driving increasingly lower completed well costs has been remarkable. If you were to assume Frankenstein wells in those basins, where would that theoretically place your well cost in peripheral lateral?

Absolutely, Derrick. So on both basins, we always look at the technical limit well, and we always strive to push that. And what we find is that technical limit keeps moving. So we're past some of the technical limits we had a year or two ago. So I don't have a direct answer for you because we're a learning, growing organization that's going to continue to drive that efficiency and cost control. But with that said, the answer is continually lower than it is today.

Travis, I think it's impressive what Diamondback achieves, and you excel at it. Considering the overall business, what do you believe is the one area that continues to progress, that low-hanging fruit that might still be available in the next 12 to 18 months regarding cost structure, reducing expenses, and improving cash margins while also enhancing shareholder returns?

Yes. Gail, it's not just one thing. And I think that's actually where you can get yourself in trouble if you just inordinately focus on one thing. It's really the combination of all the things that fit into that low-cost operations and really good execution. And I believe we've got an organization that understands their role in delivering on those. And so our focus is continually on those items that drive efficiency even if sometimes if you had to spend more because it's an emerging technology. If it translates to low overall cost, well, we'll embrace that as well, too. So there's nothing, we're just trying to squeeze every penny. We, of course, try to do that, but we also look for the best way to do things that have the greatest impact on our overall portfolio. And I'm really impressed with our new organization that essentially doubled in size in November as to how quickly everyone now, all the Diamondback employees have embraced that concept.

And then looking at the drilled wells that are well-aligned this quarter, very solid results. Can you just give a little more color around that area and kind of what you guys think about that going forward? And then what needs to be done from the standpoint of infrastructure run out down there?

Yes. Obviously, we're very impressed with the initial wells that we drilled down there, some of the best wells we've actually drilled in Pecos County. And we're going to continue to develop that with our business partner, and we've got some midstream down there that our Rattler business is actively developing now. And also, Viper has been acquiring minerals down in that area as well, too, so it's a good example of how Diamondback's different companies are really driving a lot of value for our investors.

Travis, in your prepared remarks, you mentioned a strong emphasis on adhering to the CapEx budget while also maintaining your completed well count guidance. I want to clarify mechanically, if the budget allows for spending but efficiencies result in an increased completed well count, should we anticipate that Diamondback will reduce the number of drilling rigs or completions in that scenario? Additionally, how do you view the setup for the 2020 program?

Yes. Jeff, no, we're not planning to go over that 320 gross well count for the year. I think it would be very hard for us to hit the lower half of our budget with the higher half of the completed well count. That's certainly our target. So we like to think about things at the midpoint and beating the midpoint on the best side of that guidance. So with the $2.7 billion to $3 billion budget, we're thinking internally here, we got to beat $2.85 billion.

Okay. And on the prune side of the equation there, obviously, you got the nice sale in the books. Is there anything else that you guys feel kind of compelled to turn into cash in the next, say, 6 to 12 months? I imagine you guys are always open for business if someone made you a good offer on some backdated inventory. But is there any kind of proactive effort internally to prune any other additional assets?

Yes, Jeff, as significant capital allocators, it's important to stay mindful of that. Right now, our focus in General and Administrative expenses is on several other initiatives. I’m proud that we successfully completed that divestiture, which fulfills one of the synergies we discussed at the time of acquisition. We are open to any opportunities that arise, but at the moment, we are concentrating on achieving other corporate objectives, such as prioritizing low-cost operations.

Could you provide an update on cost and capital? The CapEx performance this quarter was impressive, especially in drilling and completions, likely due to the effective tracking of cost synergies. Can you explain the key factors behind the lower-than-anticipated CapEx and whether you believe these factors will be sustainable? Additionally, even though it's still early, what do you see as the potential downside risks in deploying our budget, particularly regarding the lower half of it?

Yes. Ryan, we made a promise in December that we're going to cut activity and cut activity right away. And we've delivered on that in the first quarter. We dropped 2 spreads immediately and dropped 3 drilling rigs. I think the combined organization, we've learned a lot of things from the Energen folks and vice versa. And we've started to push down costs on the service side. So a lot of it is going to be permanent but some help from the service side in the first quarter.

Great. While this may not be a direct follow-up on M&A, it relates to scale. Another operator in the Permian Basin recently mentioned that optimal scale falls between 6 and 20 rigs in the basin, noting that the advantages diminish as you exceed that range. Additionally, another large operator has expressed concerns about their long-term scale needed to compete in the Permian. You clearly have established a good degree of scale in that area. How do you evaluate your scale and long-term position in the basin, and what level of scale do you believe is necessary to remain competitive?

Yes. Ryan, I'm not going to comment on any peer's commentary. That's up to their opinion. For us, speaking about Diamondback Energy, we certainly have seen a benefit of scale between where we were in August prior to the Energen merger and post that deal. We're certainly seeing the benefits on the cost side and a ton of benefits on the operations side of the two companies being put together.

We have successfully expanded the company from having virtually no horizontal rigs to operating over 20 horizontal rigs today. Regardless of the optimal number of rigs, which varies for each company, our goal remains the same: to be the low-cost operator, whether we are running one rig, twenty rigs, or even forty rigs. I can't determine the ideal number of rigs for our business, but I am confident that whatever quantity Diamondback has in operation, we will excel and maintain our status as the lowest-cost operator. Furthermore, as we scale, it's crucial to control our infrastructure, which is why we established an infrastructure company to manage this aspect. As our size increases, controlling infrastructure becomes a key component in developing and executing our strategy, and that’s exactly why we have created a robust infrastructure company within Diamondback.

I'm curious about your progress in achieving savings on the Midland side, as it seems you are ahead of schedule. Are you still anticipating a reduction of another $20 per foot in well costs for 2020? Where do you expect this savings to come from? It appears that you've realized savings on the contract service side. How do you plan to achieve an additional $20 reduction? Also, regarding well costs in the Delaware Basin, there are certain savings from Midland that haven’t yet been applied to Delaware, particularly in service costs and cycle times. When do you expect these improvements to catch up in the Delaware area?

David, I'll take the first question first. And the $20, the additional $20 in the Midland side was what we captured in January. So that is already in place, and we've demonstrated that this quarter. On the Delaware side going forward, so again, we're not going as far along in the development of the Delaware side as we are on the Midland side. So again, based on terms kind of third, fourth inning. So we're seeing a lot of changes in how we're drilling the wells, pad development, completion techniques, casing designs, removing casing strings, reducing what we're doing on these wells and getting better results. So you're going to see a higher rate of change over the next near-term period in the Delaware compared to the Midland side. But the numbers that we presented today are what we saw in the first quarter.

I understand. Thank you. Now for my second question. Considering that in 2020 you projected a production decline of about 36% this year and 32% going into 2020, is that primarily due to the timing of wells being brought online? Or is there an expected improvement in managing the existing operations, particularly regarding nonproductive downtime?

It's really just the benefit of having more wells on longer and slowing down the natural growth rate. Right? I mean if you look back to 2016 to today, we went from 4 operated rigs to 22. That's going to really increase the treadmill over that time period. Now with us at 21 rigs today and not looking to add 6 or 7 rigs a year anymore, naturally, your PDP decline rate is going to slow. So I mean we see that declining by about 5% from 2019 to 2020.

Appreciate the free cash flow guidance for 2020 at the $55 WTI. Just wondering what CapEx or rig count assumption has been factored in that number? And also any additional synergies beyond the secondary synergies that you have laid out are you factoring anything in?

Asit, I mean the biggest things we're factoring in is we're at 21 rigs today. I don't expect us to add more than 1 or 2 rigs in 2020. From a capital perspective, it's natural that if oil stays where it is, that service cost being recalibrated a bit to the higher side. So there's some conservatism baked into that number. Most importantly, our oil marketing contracts get significantly better in Q2 this year. But looking into 2020, we'll be exporting a majority of our barrels down to the Gulf Coast. That's going to help us from a realization perspective.

Okay. And my next question is actually on Slide 14, where it looks like the average completed lateral length has stayed fairly steady over the past several quarters. Is there an opportunity to push that number higher? And just wondering if you have any thoughts on where you see optimal pad size evolving based on your current footprint in both sides of the basin.

I'll let Mike handle the optimal pad size, but from a completed lateral length, we're going to be around that 9,500-foot level for a while. Our goal from a business development perspective is to make sure we have 10,000-foot laterals at least across our whole portfolio. So we're going to be moving at the margin, but every 100 feet certainly makes a difference from a capital efficiency perspective.

And Asit, on the Midland Basin side, we have well pads as large as 12- to 16-well pads. Again, it's area-specific. There's a lot of factors that go into what makes the optimal. And actually, the team does a great job of figuring out what that is in each one of our geographic areas. And if you go to the Delaware Basin, of course, the wells produce a lot more fluid than we have on the Midland Basin side. So typically, the pad sizes will be smaller. So there, typically we're at a 2- to 3-well pad, somewhere up to four well pads right now. Over time, that may grow, but it won't grow to the level that we have in the Midland Basin side in the near term.

I wanted to switch topics a bit and move to the Carlyle JV. You announced a couple of very strong wells last night. And on the heels of that, I was wondering if you could give a bit of a refresher on kind of what could happen with that JV, how material that could be? And really, if it could influence sort of drilling within or kind of around that JV area in Pecos County.

Tim, yes, we're certainly pleased with those well results. It's really going to be up to our partner, Carlyle, to elect to go to the next tranche of wells, and we're expecting that imminently over the long term. And I think we're confident enough in the northern half of that acreage that if we didn't have a partner, we'd drill it ourselves. We've bought a lot of minerals and have a lot of midstream in place, and the well results compete with the main block.

Okay. And then on the next tranche, how many wells would that be?

It would be just drilling out the northern half and some southern half wells. From a Diamondback perspective, it'd be a very low capital amount.

Okay. Fair enough, fair enough. And then just to hammer the repurchase kind of seem a bit more, I know, Travis, you've talked with them, you've said you see accretion and perpetuity from the repurchases. What kind of price sensitivity do you see around that if we assume, all else equal, but shares come back to that 2018 high, $135 or higher? Would you still plan to execute this? Or do you feel like there is sort of a tactical nature to the intensity based on what the share price is doing?

Yes. So look, we're committed to this capital share return program, and I think we've allowed ourselves enough flexibility to figure out what the best way to drive that value to our shareholders is going to be, whether it's in the form of cash or share repurchases. And that's something the Board will continue to evaluate. But the key here is that this is not just a onetime event. This is the Board's signaling that this is an ongoing return of capital strategy that's underpinned by our free cash flow growth profile and our production growth profile well into the future.

I just want to follow up a little bit on the M&A. You've had excellent success pursuing that and delivering on the synergies you promised with the Energen merger. It's not always the case that with large, corporate M&A, the synergies that actually come through and they're quite visible. And from our perspective, it seems like there's still a number of opportunities where you could put your operational model and cost structure on other assets and extract a lot of value at the same time with your buyback announcements. We'd like to think your stock is really underappreciated. Can you just talk about how you think about the potential opportunities in the space and how you balance that with the way you see your stock price right now?

Yes, Drew, I don't think it's my place to speculate on basin-wide M&A activities. What we believe is that repurchasing our shares offers the greatest value on the M&A front, and we are discussing a $2 billion acquisition.

Certainly, Travis, we'd agree. Your stock is very accretive. So in terms of the $2 billion buyback, can you talk about that figure specifically? Can you talk about funding it with full free cash flow and proceeds from asset sales? Is that $2 billion number, you think you have line of sight to? Or does that incorporate a potential upside of proceeds from asset sales or free cash flow to prices to the upside? Are there upside to the $2 billion number? How do you guys think about that?

Drew, that's the number for now. If we outperform, then we'll go back and talk to our Board and adjust accordingly. But we see it at strip. And with the catalysts we have on the proceeds side, we certainly see visibility to executing on that number through the end of 2020.

My first one is just a follow-up on the free cash flow in 2020 at $55 WTI commentary. I know that a lot of the moving pieces, like service recalibration, for example, you just mentioned would flex alongside changes in crude pricing. But are there any sensitivities that you can share with us around that free cash flow figure as you think about variability in WTI?

Jeff, we've always reacted to WTI to flex up or down at the margin. I think what's changing now is that our plan is pretty set, and there's not going to be a wild swing in rig count up. Now there might be a wild swing in rig count down if we have to adjust if this commodity falls out of bed. But overall, we feel like we're creating an execution machine that's going to complete a little over 300 wells this year and a little bit of growth on top of that next year.

Got it. Appreciate that. And then my second one is just on the timing of activity. Is there any additional detail you can speak to on both how Q1 played out? And maybe what your thoughts are just on the rest of the year, just towards giving us a sense of what we could expect in terms of production trajectory from here and how timing can play into that?

Yes. No, I certainly think we're going to grow into Q2. We completed 82 wells in Q1, with 19 of those wells coming on in the last 2 weeks of the year. So we're certainly going to grow into Q2. Q3 will be the first month without the 6,500 barrels a day of production that we listed as for sale. That's expected to close July 1, so I expect us to grow into Q3, just not as much as Q2. And then another consistent quarter into Q4.

I would like to inquire about some Delaware Basin assets that we haven't discussed much, particularly the north-central area in Lea County. I believe this is among the most valuable acreage on a per-acre basis in the Permian. However, it seems you don't have the same scale there as you do in the ReWard area or other locations in the basin. Based on your perspective, do you think these assets are more likely to be part of your growth strategy or more likely to be subject to pruning?

We have a solid position that allows us to implement the capital plan there, although it's not as large as our other key development areas. Our business development team is actively looking to trade and consolidate that acreage to enhance our operated positions. With the Energen acquisition, we gained a substantial amount of non-operated assets compared to what we traditionally held at Diamondback. We're working to convert that non-operated position into a somewhat larger operated position. We're definitely open to operating in New Mexico, given the promising well results in that region, and we're planning to move forward with that if we can strengthen our position a bit.

Got it. That's helpful. And so I'd say if you can transition it to operated, then it would make more sense. But Travis, I want to go back to...

There's an operated position there today. Our job is to make sure that operated position grows, and so it's more attractive for us to develop long term.

I want to revisit a point you made in your prepared remarks and reiterated here during the Q&A about the idea that buying back your own stock is the best acquisition opportunity you see. I suspect other operators might view it similarly. My question is, what metrics do you use, or are you willing to share, that help you evaluate the difference between considering a publicly traded equity acquisition, even if it’s your own stock, versus pursuing a specific asset purchase?

Certainly, the cash flow profile of any acquisition target is one of the most important factors we evaluate. We aim for cash flow per share accretion, but other aspects also matter. It must be accretive on reserves and rank in the top quartile of our portfolio, allowing us to allocate capital effectively and enhance operational excellence. As we achieve our current scale and maintain our commitment to living within cash flow, which we've been dedicated to since 2015, the cash flow aspect of acquisition targets becomes increasingly significant.

I think on top of that, Charles, if you think about it from an engineering perspective, we feel that we're trading in the high-teens PV with a 9% cost of capital. So buying back our stock is a great use of that capital.

And back on the targets, I can't count the number of times I've used the word accretive. It's got to be an accretive trade, and those metrics I laid out to you, we've got to look for accretion on that. And then we'll never do anything that'll put Mike's organization at risk of not being the best-in-class executor. So...

Honestly, guys, that's helpful insight. It's that focus on the near-term cash flow accretion. So I appreciate those comments.

Just quickly back to the CapEx theme, maybe for Kaes. Obviously, capital spend in trend is off to a very favorable start in 1Q. How does it set up the cadence for the rest of the year? Is there perhaps some bigger infrastructure spend in any one particular quarter?

Yes. Richard, I think from the infrastructure perspective, the Rattler budget, which is the midstream budget, is going to be fairly consistent through the year on a quarterly basis. We spent about a quarter of that budget in Q1. On the infrastructure side, we expect that piece to pick up a bit in Q2 and Q3. That number was about 19% of the total budget for the year. And then on the D&C side, I think we're going to have a little bit higher working interest and a little bit higher average lateral length in the second quarter. So I think it's logical that the D&C gross CapEx number picks up a bit with that higher working interest.

At the DUG Permian Conference a couple of weeks ago, there was a private operator discussing some solid Barnett oil well results that we're seeing near your Limelight acreage. What is your outlook for that acreage? I know it's not a big position, but how do you see that acreage playing out? And when do you expect to begin appraisal there? It'll probably be a fourth quarter event this year, maybe first quarter next year. But we're still excited about that block we put together. Really, really low cost. And we're pleased to see offset results that continue to support our thesis as to why that was a good area to explore.

Well done on the execution this quarter. Just curious if you still have a decent amount of inventory, I guess, particularly in the Midland Basin and kind of the other category. I'm just curious if you have any plans for appraising any of that or derisking any of that over the course of 2019.

Michael, I think we've always been a fast follower, and we're very focused on the highest rate of return zones. We're certainly codeveloping more zones as well as A&D. I think in that other category, we've seen some really good results from some offset operators that might change our plans in the future, but not in a meaningful way. I think from an overall capital allocation perspective, the highest rate of return zones are still going to get the vast majority of our capital.

Thank you again to everyone participating in today's call. If you've got any questions, please contact us using the information provided.