Vital Energy Inc (VTLE) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to Laredo Petroleum, Inc. First Quarter 2017 Earnings Conference Call. My name is Chanel, and I will be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

It is now my pleasure to introduce Mr. Ron Hagood, Director of Investor Relations. You may proceed, sir.

Thank you, and good morning. Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Dan Schooley, Senior Vice President, Operations; James Courtier, Vice President, Exploration and Geosciences Technology; as well as other additional members of our management team.

Before we begin this morning, let me remind you that during today's call, we'll be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.

The company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we'll be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures. Reconciliations of GAAP net income to these non-GAAP financial measures are included in yesterday's news release.

Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for first quarter of 2017. If you do not have a copy of this news release or presentation, you may access it on the company's website at www.laredopetro.com.

I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer.

Thanks, Ron, and good morning, everyone. Thank you for joining Laredo's first quarter 2017 earnings conference call. In the first quarter, the company again fired on all cylinders. Our wells continue to outperform our type curves, and we maintained our already low capital and operating cost. We demonstrated our operational strengths, as we've put a 9-well package on production, spudded 3 wells with planned lateral lengths exceeding 15,000 feet. Fact, these were the longest drilled laterals ever existed in the basin.

Company is executing, as we have said it would, and we believe there is upside from here. We're continually driving more value from our continuous acreage base, our technology and our infrastructure.

That key to the value creation we're achieving is our continuous acreage position. This drives our ability to drill return enhancing long laterals; our ability to utilize our production corridors to lower operational capital cost; and direct our strategy to high-density development across our acreage. All of this is facilitated by our ability to analyze large amounts of data to accelerate learnings and formulate best practices.

Our in-house technology development enables identification and quantification of discrete production drivers. This has now progressed to advanced reservoir fraction modeling that, when incorporated into our technology workflows, is expected to increase the value of our acreage through the high-density development of each drilling spacing unit. Laredo is extremely well situated to expedite value creation of our high-quality inventory, with no debt due for approximately 5 years, substantive oil and natural gas hedges in 2017, manageable leveraged ratios and liquidity of more than $900 million. We are positioned to develop and execute the optimal long-term plan for our asset.

I would now like to turn it over to James to further elaborate on our technology and testing.

Thank you, Randy. We remain focused on maximizing value from our Midland Basin assets in the most capital-efficient manner through applying state-of-the-art technology. To assist in this regard, Laredo has continued to evolve its proprietary earth model workflows to the next level to make the best decisions on vertical and horizontal spacing and completion design. Laredo's Earth Model was originally developed to assess the impact of geology on the horizontal well production, directing optimal landing point selection from both our trajectories. We have refined the data analytics and geocellular modeling elements of our Earth Model workflows to develop corporate competencies in multivariate analytics and high-resolution, 3-dimensional reservoir and completion modeling.

Laredo's extensive high-quality data set has proved a vital element in this endeavor, providing an assessment of the individual impact of geologic completion and well design variables on horizontal well production. This process has enabled Laredo to fully leverage its contiguous acreage base to support drilling extended lateral lengths from 10,000 feet to more than 15,000 feet today, which we believe will provide superior economic returns.

Sophisticated data-driven models have assisted in understanding how production is affecting specifically due to horizontal and vertical well spacing, minimizing parent-child impact, deriving the maximum value from each drilling spacing unit. This led to a current development strategy of completing large packages of wells simultaneously wherever possible.

They were in the process of further refining our development plan by investing multiple landing points within individual formations, increased proppant concentrations, tighter perforation cluster spacing, along with other proprietary techniques and their relative effects on well spacing. Confirming hydraulic fracture simulation modeling on high-resolution, 3-dimensional geo models provides benefits of assessing a wide array of completion designs within various well spacing configurations to develop an optimal design before conducting field trials. We have validated our fraction simulation models with microseismic data, rate trends and analysis and well performance. Confirming tighter perforation cluster spacing and more sand are resulting in increased propped surface area, greater near wellbore fracture complexity and overall tighter and more consistent hydraulic fracture geometries around the wellbore. We believe applying these spacing and completion workflows will increase the value of each spacing unit, as it optimizes well density and total resource recovery.

This becomes increasingly important as commodity price and service cost environments change, while result in spacing and completion designs may differ in order to achieve the highest value. We will be testing this concept with a 6-well spacing test that will spud during the second quarter. 5 of the wells will target both the Upper and Middle Wolfcamp with Chevron patent to test the co-development concept to several landing points in stacked formations. Additionally, recent core analysis has reconfirmed the potential of the lower Wolfcamp, which will comprise the 6th well in this test. We expect to see initial results from this test around the end of this year.

I will now pass over to Dan for an operational update.

Thank you, James, and good morning. Laredo continue to demonstrate its operation excellence during the first quarter, completed drilling operations on 2 wells with drilled lateral lengths greater than 14,000 feet, and spudded 3 wells of planned drilled lateral lengths of approximately 15,500 feet. In the first quarter, we completed a 9-well package that tested various stimulation designs, 5 wells with higher proppant concentrations and 3 with tighter perforation cluster spacing. And we kept capital and operating costs low in the face of increased demand for services and pricing pressures.

During the first quarter, we produced 52,405 BOE per day, an increase of 13% from the first quarter of 2016. We completed 13 wells during the quarter, averaging approximately 9,900 feet of completed lateral length. As I mentioned, 9 of the wells were completed as a single package. 3 of the wells were part of another 9-well package, with the remaining 6 wells of the package to be second-quarter completions. The operational efficiencies of drilling and completing wells as packages cannot be overemphasized. The savings associated with batch drilling and zipper fracs have helped offset increased service pricing in the first quarter.

We continue to successfully push the envelope in the drilling of long laterals. According to IHS, we have drilled the 3 longest horizontal wells in the Permian Basin and drilled and completed 6th of the 10 longest. The 3 15,000-foot-plus wells were drilled in an average of 21 days from rig accept to rig release. As noted on Page 10 of our company presentation, the economics of drilling these wells is extremely compelling, especially as we see no degradation involvements with the longer laterals.

We continue to try and hold the line on service cost increases. But as you can imagine, no operator was immune from this trend. While our well costs were in line with our expectations in the first quarter, we began to see pricing for stimulation services increase at the end of the quarter. We are reviewing our options with service providers to modify pricing based on different parameters, evaluating different providers and identifying alternate means of sourcing items, usually purchased from the service providers.

The company has not increased its budget and well cost assumptions at this time, but continues to review our assumptions based on actual well look-backs, on which we evaluate the economics of wells we approve for development.

For the second quarter of 2017, we expect to complete approximately 18 wells. Approximately 80% of the completions are expected to be divided between the upper and middle Wolfcamp, with 4 wells expected to be in the Cline. Well completions are expected to be relatively evenly distributed throughout the quarter.

Laredo continues to recognize outsized benefits relative to its capital investment in its field infrastructure and production corridors. During the first quarter, we gathered on pipe 65% of our total flowback in produced water, producing a benefit of approximately $1.9 million. Additionally, 30% of flowback in produced water was sent to LMS water treatment facility, which, in conjunction with utilizing recycled water and completions, produced a benefit of approximately $1 million. These benefits are expected to grow $3.3 million by the fourth quarter of 2017, as additional wells are developed along production corridors and volumes handled by our water system increase with these new wells.

The other main driver of infrastructure benefits is LMS' crude oil gathering system. The system gathered 73% of Laredo's total gross operating production during the first quarter, producing a benefit of approximately $2.7 million, like the water system as wells are developed along production corridors, volumes gathered by the system will increase. We expect gathered volumes to increase approximately 60% by fourth quarter of 2017, increasing the benefit to Laredo to approximately $4.3 million during the fourth quarter of 2017. The Medallion-Midland Basin system, in which we own 49% interest, continued to grow as activity in the basin accelerated. First quarter 2017 volumes grew to approximately 149,000 barrels of oil per day, an increase of 79% from the first quarter of 2016, an increase of 16% from the fourth quarter of 2016. Volumes on the system are expected to grow to an average daily of 175,000 barrels of oil per day in the second quarter of 2017.

With that, I will turn the call over to Rick.

Thank you, Dan, and good morning. As you saw in last night's earnings release, Laredo's first quarter 2017 production and unit cost were in line with our expectations and the quarterly guidance that we've previously provided. Production volumes were slightly under the range midpoint, reflecting the timing of production, as large well packages came online and slightly longer cycle times associated with some of the testing activities that James and Dan discussed. Keep in mind that increased volumes associated with the fourth horizontal rig that was recently added will begin having a meaningful production impact during the second quarter. We have reiterated our second quarter guidance range of 55,000 to 58,000 barrels of oil equivalent per day and remain on track with our original production guidance for the first half of 2017. We continue to expect full year production growth to exceed 15%.

Our ongoing focus on cost control continue to show benefits as unit cost, both cash and total, each tracked at or below the low end of our guidance range. We have further reduced our unit cost estimates for the second quarter, as detailed in the guidance reflected in yesterday's earnings release.

Adjusted EBITDA for the first quarter of 2017 increased $9 million from the prior-year quarter to $107 million. This is up slightly from the fourth quarter of 2016, after adjusting for the $30 million reduction in cash settlements received from derivatives net of premiums paid. We continue to maintain an active hedging program to protect our cash obligations for debt service, employee costs and maintain a reasonable capital program. To accomplish this, we consistently review our current hedge position and regularly add to it through the use of puts, collars and swaps.

Details of our strong hedge position are shown on pages 27 and 28 of the corporate presentation that was furnished last night and available on our website. Please note that we have recently added 30,000 MMBtu per day of natural gas hedges for 2018. One item to keep in mind about our natural gas hedges is that they are all priced at WAHA. Therefore, our 2017 natural gas hedges, which have a weighted average floor price of $2.75 per MMBtu at WAHA are equivalent to approximately $3.20 per MMBtu at Henry Hub based on recent basis differentials.

During the first quarter, cash flow from operating activities, coupled with the proceeds from the small acreage sale previously announced, more than funded the approximate $109 million invested in development activities during the quarter. Included in this amount is the additional cost for testing of the 5 wells, in which we used higher proppant concentrations and the additional cost of testing tighter perf cluster spacing. Also included in this amount is increased activity associated with the addition of a fourth rig. At the end of the quarter, we had ongoing activities occurring on 15 wells and another 6 wells waiting on completion. In the second quarter, we expect production and cost-incurred figures to be more aligned as we fully integrate the fourth rig into our drilling program.

As Dan mentioned, we are seeing potential upward pressure on service cost. Currently, we expect to fully execute our 2017 program within the previously-announced $530 million budget, although sustained increase in cost could change this expectation. As James mentioned, we continue to test multiple completion methods. Should any of these be fully in the remainder of 2017 program, budget assumptions may also need to be adjusted.

Earlier this week, we completed an amendment to our senior secured credit facility. This facility now has a borrowing base of $1 billion, up from $815 million previously, with a maturity extended to 2022. We currently have $75 million drawn on this facility, resulting in approximately $945 million of liquidity, including cash on hand.

As with the previous facility, our interest in the Medallion-Midland Basin System is not pledged as collateral. Additionally, this week, the $500 million face amount of our 7 3/8% notes became callable, which when coupled with a $450 million of 5 5/8% notes that are also callable today, totals $950 million of optionalities surrounding our long-term debt. We believe the combination of our substantial liquidity and ability to call more than 70% of our long-term debt provides significant financial flexibility to the company. This enables the company to accelerate value creation as our data guides our value-enhancing development plan. Production growth alone does not necessarily equate to value creation. As we use our data-driven strategy to determine the optimal development path, we expect to take a measured approach to growth that preserves efficiencies and extracts the full value of our resource.

Operator, at this time, would you please open the lines for any questions?

(Operator Instructions) Our first question comes from the line of Eric Whitfield of Stifel.

There are definitely several powerful updates in your PowerPoint. Looking at Page 9, I thought that slide was particularly impressive, and wanted to ask you guys if you have a view on the baseline degradation one should expect from long lateral development. And if so, what factors do you attribute to your consistent well performance on a peripheral lateral basis?

We've consistently, I think, said that we think -- we just have so much evidence that the longer laterals are more economic. And I think I've said in the past that we had some concern early on when we went to -- from 4,000 to 5,000, 5,000 to 7,500 and so on and so forth about the operations and the ability to stimulate that last thousand feet or so of the well. But I think what we're trying to show is that we've collected enough data now on enough long laterals that we're pretty comfortable. We're not seeing any degradation, and that's substantively changes the economics. And again, our acreage base allows us to do that, Eric. So we think all the data we've seen, and we probably have as much or more than anybody, that we're actually able to stimulate the last thousand feet of that wellbore, just like the first thousand feet.

That's great. And then moving over to Page 17. When I'm reading that chart, the thing that I'm trying to understand is, how much of the improved outperformance, which is 40% on that chart, do you attribute to your proppant intensity versus controlled flowback?

The flowback is interesting to us. And I may let Jason talk a second about the managed flowback, but our view has been fairly consistently all along that this whole focus on 24 RIPs was probably not warranted in the sense of we worry about, ultimately, are you damaging the reservoir? Are you pulling sand back in? Are you clogging up what you just fracked? And I don't know that we have a good handle on the managed flowback versus optimizations. But I think it's, again, those things that you've got to have. You need to have enough data and enough wells to test the concept. And so I would think it's probably too early on the 2,400-pound of sands to really talk. We've got a lot more data on the 1,800-pound sand. Jason, do you want to add anything on the managed flowback?

Sure. This is Jason Greenwald, Vice President, Reservoir Engineering. I think the only point I would add to this is that in this unconventional system, we do think a lot of these design elements are interlinked. So really, we do think the outperformance that we're seeing here is really a combination of many of the (inaudible) managed drawdown and the proppant (inaudible) as 2 examples. Hopefully, that helped.

It does. And again, we're early in the process right now. But it's all consistently working. You're just trying to understand which of knobs is perhaps having a bigger impact than the other?

Well, as you know, we've been slow to claim credit. We've seen many a time in my career where 1 or 2 really good wells -- and you relied on that data. And conversely, some that didn't work, we think that you need a substantive database, a lot of analytical. And we're coming more and more comfortable with our multi-variant and best practices approach of this. So for us, it's a progression when you have the volume of rock that we have that's capable of producing oil. We want to make sure that we don't do anything that we come back to regret in terms of claiming credit. But we're showing you real numbers. It's working.

It is. And Randy, my last question for you guys is on Page 19. With that pilot, can you comment on what you're attempting to test with the uppermost number and the top right, and then the lowermost number on the bottom left? And the reason I asked the question is because they don't appear to be that close in proximity to the other wells. So it seems like there's something else you're doing with that design that you're testing.

I'll probably let James comment some on that. But what we've said for some time is that the industry, in general, has spaced wells too closely time-after-time-after-time going back the 80s, and the Austin Chalk and even going back further than that. What we said at Laredo was that if we didn't space closely, we still had lots of inventory to drill. And what we're saying now is that we're actively getting the data and the testing that we need to figure out the spacing. We've talked about it several times that we have, for example, in the Upper Wolfcamp, 2 or 3 different landing points. In the Middle, we've got 2 or 3. So what we're really trying to do is figure out optimal NPV spacing. And if we can do that right, we dramatically increase the inventory of locations and dramatically increase the NPV of this volume of rock that we have. James, did I...

So yes, I'd just add to that. But in the Upper Wolfcamp and the Middle Wolfcamp, we've got about 3 separate landing points in both of those zones, where we've drilled wells previously successfully. So they're being very good wells. So what we're attempting to do here is to combine multiple landing points at the same time with a co-development strategy. So what we're showing is 6 different zones in the Upper and the Middle Wolfcamp. Those zones aren't necessarily present everywhere. But in this particular test, we're testing 3 zones, 3 landing points in the Upper Wolfcamp and 1 in the Middle Wolfcamp together.

Your question about the Lower Wolfcamp is, we've drilled the Lower Wolfcamp on our acreage, it was pre-Earth Model, relatively short laterals, and probably nowhere near as good a completions as we would do on them today. And as you know, there are some Lower Wolfcamp news coming out, a little deeper in the basin, that's pretty spectacular. So I think it's -- we have multiple targets that, at some point, we've got to go look at. We've talked about this before. Some of our better wells are Cline. Cline's a good one to drill because it gets all the depths held mostly. So I think over time, we're going to continue to look at Lower Wolfcamp, continue to look at Cline, which Dan talked about. At some point, we'd say that we need to go look at Spraberry. But the real excitement for us today is if we can figure out and prove up the concept of having multiple landing zones spaced fairly close together in the Upper and Middle Wolfcamp.

And our next question comes from the line of James Spicer of Wells Fargo.

You talked about your bonds being callable. I think you're mentioning that from the context of a refinancing as opposed to taking those out and actually reducing your total debt amount. Maybe you could just clarify that. And then more generally, talk about the priorities right now with respect to the balance sheet.

Yes. As we mentioned during the call, $950 million of notes are callable today. So that gives us significant optionality and flexibility of what we may do with our balance sheet. It is not meant to give any indication of what we do or may or may not do going forward. But we do have that option. We're seeing very positive results from our drilling program. The liquidity that we have, the flexibility around those bonds gives us a significant amount of optionality of how we go about further acceleration of the development of the properties.

Okay, that's helpful. And then I was also wondering, one recurring topic that I know people discuss here is a potential monetization of your interest in Medallion. Can you just share your latest thoughts on that?

We -- our latest thoughts are basically the same thing we've been saying for a year or so. Last quarter, we did -- went into a little more detail on talking about Medallion. Dan mentioned the -- what we consider a fairly rapid expansion in the EBITDA in the barrels going through Medallion, we think that probably translate, at some point, into an overall value for the system. But I think our view is that if the more people drill in the Midland Basin, the more crude probably goes through Medallion. So I think there'll be a correct time for us to make a decision. But we do think the value creation, whether we ultimately monetize it or whether we keep the EBITDA or whatever we do, there's a number of choices, we think that value creation and the possible barrels going through and the EBITDA growth are all moving in the right direction pretty fast.

Okay, appreciate that. And then one more, just last housekeeping item, if I could. You have a $59.5 million proceeds from dispositions in your cash flow statement. What's that related to?

That's the sale of a small piece of acreage that we had on the northern portion of our property that we have previously announced. That sale wasn't affected with drilling completed in early January. And we had a minimal amount of production. But when you're looking at the comparison of first quarter versus prior quarters there's several hundred barrels a day of production associated with that acreage.

And our next question comes from the line of Kashy Harrison of Simmons Piper Jaffray.

So with respect to drilling longer laterals, at what point do you think you would completely transition to a program or transition to a program where you primarily employed 14,000-foot or 15,000-foot laterals as opposed to your average for next quarter, which is about 10,000?

That's a good question. I think our view is that we're recognizing the longer values -- the longer laterals do have greater economic value to us. And what we've done is we've set out on this process of really trying to figure out the appropriate spacing and what landing zone we can do in the Upper and the Middle. And what we've chosen to do is to not vary too many variables at one time. A lot of our acreage supports longer laterals. I think once we understand the spacing, both vertically and horizontally, we'll be looking at drilling more of the longer laterals then we're doing this year.

Got it. And then just a quick follow-up on the 2,400-pound completions. About how many -- about how much data -- how many days of data do you think you would need before you could definitively say whether it's adding economic value or not?

We've seen, even in acreage surrounding us, but also throughout my career, where early data was positive. And ultimately, that, whatever we were testing, proved not to be economic. 90 days of good production above your type curve is meaningful. But so many times, we've seen things that revert back to the mean after some months. And the volume above the type curve when you integrate, it didn't pay out the additional cost. So I think, for us, we're a little bit different there. As I said earlier, we're not going to claim credit based upon 4 or 5 good wells over 2 or 3 months. I think we're going to want to see a substantive number of wells and a substantive production history being a year or so. It just doesn't -- the early data are sometimes pretty indicative, but they're also -- you just need to see substantive production data to really call it good. And one point I'll point out on that 2,400-pound slide is that those are also managed drawdowns. So we're keeping kind of a little bit of a cap on the first month or 2 or 3 of production. So what you're seeing is really exciting, but we kind of have this constant evaluation process. And for us, we're going to see -- we're going to want to see substantive production history on a number of wells.

The only thing I'd add to that, that gives you the performance of those enhanced completions, but they're going to be looked at and reviewed from an economic standpoint based upon commodity prices as well as service costs. And so that is an ongoing process with every well as we go about designing their completion for that. So we do not expect to ever get to a specific standard design that you're going to march across the acreage with. It needs to be looked at individually from an economic return standpoint.

To reexplain, we drilled over 300 now horizontal wells. I'm not sure exactly how many, but we're on version 300-plus of our completion design. We are using all of our data to pick that landing point. Then we drill the well. We look at the data we get from drilling the well after it's drilled. And then we kind of custom fit that completion design to what we see in that wellbore. I think that continues forever around here.

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

I just wanted to follow up on a couple other previous questions out there. I guess, in regard to the longer laterals and the 15,000 footers, how much -- how many of those do you have in your inventory? I mean, could you drill 100% 15,000-foot laterals going forward? Or is it a limited portion of the inventory?

When you look at our inventory, it's pretty blocked up. And the facts are I think that we've got several years of drilling at 15,000-foot. But we get more inventory at 10,000, more inventory at 5,000. I think the message is that we've got a lot of options that we're doing there that make us think that the longer laterals are better. So we'd like that. And I think as we get better handles on our spacing, we'll be drilling a lot more longer laterals. And the -- what's happening, I think, and I was struggling how to best point this out, is that the land grabs over, I think, to a significant deal. And I think you can see that people are starting to really recognize the value of longer laterals. And so I think there's going to be more effort put on people getting together and doing land trades, land swaps or land sales or whatever to drill those longer laterals. The important thing to us is that we're not seeing any degradation. So when we get there, it's going to be extremely economical to drill. The interesting thing also on that, I think, which is we've talked about it a lot in the past, is it takes a lot of infrastructure, especially water, but also handling the flush production coming back to drill longer laterals. If you're drilling 7,500-foot one-off wells, then you don't need as much infrastructure. We've got the infrastructure in place, and we've proven that we can handle the water needs with our in-field infrastructure. And the Medallion system, we've proven that we can handle the flushed oil production coming back. Same thing with our wet gas going out. So the corridors, the blocked up acreage, our water handling facilities all make us comfortable that we're going to be drilling longer laterals for some time to come. It's a long-winded answer, but hopefully, Chris, it helped out.

Yes, got it. And then on Slide 19, the co-development of the landing points. It definitely looks like there's a lot of potential upside to the inventory for all these different landing points. What's the implied spacing here of this specific test, and what the potential upside would be to your inventory just from this specific pilot that you're doing out here?

Yes. There's some risk on that slide. But a couple of points I'll make, and then I'll see if someone else wants to chime in here, but we've tested each one of those zones individually. So we know that, for example, the 3 zones in the upper and the 2 in the middle or 3 in the middle will produce as a standalone horizontal well. So what we're really trying to do is see if we can effectively double down. And it has a huge impact on inventory and the overall NPV of the company. James, do you want -- or some -- Jason, you want...

Yes. No, I can chip in here. So we do have a number of tests across our acreage position testing, spacing, and then a Chevron configuration like what we've displayed on Slide 19. In terms of what's the kind of equivalent spacing across those tests, it's really kind of 330 feet to 660 feet, kind of between 2 landing zones, kind of per formation, and this is almost always a Chevron configuration. And so specifically, on Slide 19, what we're testing here in the Upper Wolfcamp is really 18 wells per section, with an upside to 24 wells per section across these 4 landing zones.

Okay. 18 just in the Upper Wolfcamp? Or Upper or Middle?

That's across both.

And our next question comes from the line of Dan McSpirit of BMO Capital Markets.

Just to clarify, what percentage of acreage can accommodate wells with lateral lengths of 15,000 feet or greater?

We were asked that question a little earlier. I think the answer is blocked-up acreage, I'm not going to give you the number. But the blocked-up acreage, our infrastructure, our ability to handle water give us some confidence that we're going to drill longer laterals. And whether that's 12 or 14 or 15, we'll have to see. There are some areas to where 1 or 2 small acreage additions to us would open that up some, but it's clearly something that we're pretty excited about. It's -- currently, it's in some of our zones. It's years of inventory. So I think -- I don't think we're going to run out and drill only 15,000-foot laterals. We were drilling 10,000-foot laterals and having to normalize our information down to a 10,000-foot length. Many others, we're having to normalize up. And I think there's a little bit of a viewpoint that, for example, in the Cline and Lower Wolfcamp, where we have less drilling. That might well lend itself very, very amenably to the longer laterals. So that -- I'm not giving you a number. I know that, but I think that answer's in progress.

Okay, okay, that's great. And as a follow-up to that. Just to clarify, for my own understanding here, what you identify as the Lower Wolfcamp is the same as what others identify as, say, the Wolfcamp C. Is that correct?

Yes. I think you probably ought to ask them. I think it's kind of directionally correct. But we started off that nomenclature from the railroad commission years ago. It never changed.

Got it, okay. And appreciating that you have drilled some, I guess, from pre-Earth Model Lower Wolfcamp wells. How does the product mix on those wells differ from, say, the Upper Wolfcamp, if at all?

The Lower Wolfcamp we drilled, I don't think we drilled in any several years. So they were kind of early in the game stuff and, I think in some ways, kind of like some of our early Cline. And the results were kind of scattered. There's some of those that we don't like. There's some that are pretty decent. But I think the message is not to oversimplify it. But we've got -- we now know what we've been saying for several years, and we've proved it again. We've got 4,000-, 4,500-, 5,000-foot thick section of rock that we know, unequivocally, is capable of production. So it's a question of how do we best get that economically developed for the best NPV for the company.

And our next question comes from the line of Stephen Thomas of Brenham Capital.

I just had a quick question on Medallion and the throughput volumes that you guided to for Q2. Is it fair for us to assume that in that 17% to 19% growth sequentially for the rest of this year?

I think what we -- I think, Dan, you can help me out here. But I think on Page 27, or was it 26, whatever, 26, we gave you what we thought the EBITDA growth was going to be for the year in Page 25 in the presentation, and that we think that kind of growth is kind of where we view going forward. We're not making a lot of projections. But I think it's dependent upon the speed in which third-party people drill in the Midland Basin. And under acreage at, one way or another, puts that throughput through Medallion. So if you look at that growth in third-party volumes going through there, we like that growth. And I think our view is that whatever percentage that continues, we think it is up and to the right.

Okay. And -- yes. And then my follow-up question. Given some of the recent transactions of systems pretty close to Medallion and the multiples that those parties have received, and just the EBITDA growth that your system is projecting and the eventual throughput, it seems like on our math, the valuation is over $1 billion net to Laredo. You'd think that, that would be a nice positive catalyst for the stock. And certainly, your balance sheet could use an inflow of $1 billion. Is the apprehension to really pursue a process or really discussed details are on the process? Is that more to do with the fact that your private equity partners, the majority owner of this system, and they're really the ones at liberty to discuss a process? Or is there just something else there that we might be missing?

One of the things that we've said before and -- is that we like -- the Medallion system gave us the operational things that we require. We pay for firm transportation out of the basins, such that if a basin differential blows out again, like it did a couple of years ago, we can take our crude to the Gulf. It allows us not to have to truck very much of our oil. So those things that we've captured we keep, whether we own Medallion or not. We've also said that we've made the investment in Medallion, and it's turned around now to where the EBITDA coming off Medallion is such that we could reinvest that EBITDA into a very, very high rate of return drilling location. So we think we have a lot of optionality with Medallion. And there will be a time in which we'll make a decision on what to do it with it. But I'm excited about the future growth of Medallion.

The only thing I'd add to that, Chris, is -- or excuse me, Steve, is that we do carry probably a little more debt than some of our peers. However that debt is extremely manageable, none of it's due prior to 2022. We are very well hedged. So one of our core competencies, we believe, in purposes of our hedging program, is to make sure that we always have our debt service or G&A and a reasonable capital program cover. So we are very comfortable with the debt that we have, but also we have significant optionality around, that as we discussed earlier, in that 70% of that long-term debt, we're actually about 73% of that long-term note, is callable. And we have a meaningful amount of liquidity that gives us, we believe, significant flexibility to do what we think is best for our shareholders in maximizing the value of the company.

And I'm showing no further questions at this time. I would now like to turn the call over to Mr. Ron Hagood for closing remarks.

Thank you for joining us for our first quarter update. This concludes our call, and have a good morning.

Ladies and gentlemen, thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day.